-----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, AMh3pd3TrShlKaO9f9bQUjFqFsfD4XoU2I1v84jeU4WoT+yWsYeMYOmuxSkO+7Qc DIhMkkRlCTVXyCCxVYs1PQ== 0000950168-99-000764.txt : 19990319 0000950168-99-000764.hdr.sgml : 19990319 ACCESSION NUMBER: 0000950168-99-000764 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990318 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: 99567982 BUSINESS ADDRESS: STREET 1: 39 W LEXINGTON ST STREET 2: CHARLES CTR CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4102345511 10-K 1 BALTIMORE GAS AND ELECTRIC COMPANY 10-K - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 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 1-1910 DECEMBER 31, 1998 Commission file number
--------------- BALTIMORE GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) MARYLAND 52-0280210 (State of incorporation) (I.R.S. Employer Identification No.) 39 W. LEXINGTON STREET, 21201 BALTIMORE, MARYLAND (Zip Code) (Address of principal executive offices) 410-783-5920 (Registrant's 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. Common Stock -- Without Par Value Chicago Stock Exchange, Inc. } Pacific Stock Exchange, Inc. 7.16% Trust Originated Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust I, fully and } New York Stock Exchange, Inc. 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 registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes x No . Indicate 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 registrant's 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. [ ] Aggregate market value of Common Stock, without par value, held by non-affiliates as of February 26, 1999 was approximately $3,823,612,000 based upon New York Stock Exchange composite transaction closing price. COMMON STOCK, WITHOUT PAR VALUE -- 149,556,416 SHARES OUTSTANDING ON FEBRUARY 26, 1999. DOCUMENTS INCORPORATED BY REFERENCE PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE - ------------------- ------------------------------------------------------------ III Certain sections of the Proxy Statement/Prospectus on Form S-4 for a share exchange between Constellation Energy Group, Inc. and the common shareholders of Baltimore Gas and Electric Company and the Annual Meeting of Shareholders of Baltimore Gas and Electric Company to be held on April 16, 1999 (Proxy Statement). - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- TABLE OF CONTENTS PAGE -------- FORWARD LOOKING STATEMENTS ................................ 1 PART I Item 1 -- Business Overview of Consolidated Business .......... 1 Electric Business Electric Regulatory Matters and Competition ................................ 3 Electric Rate Matters ...................... 4 Nuclear Operations ......................... 5 Electric Load Management, Energy, and Capacity Purchases ..................... 5 Fuel for Electric Generation ............... 6 Electric Operating Statistics .............. 8 Gas Business Gas Regulatory Matters and Competition ................................ 9 Gas Operations ............................. 9 Gas Rate Matters ........................... 10 Gas Operating Statistics ................... 11 Franchises ................................. 12 Diversified Businesses ..................... 12 Consolidated Capital Requirements .......... 14 Environmental Matters ...................... 14 Employees .................................. 17 Item 2 -- Properties ................................. 17 Item 3 -- Legal Proceedings .......................... 18 Item 4 -- Submission of Matters to a Vote of Security Holders ........................... 19 Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation S-K) ............................ 20 PAGE -------- 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 ................................. 23 Item 7A -- Quantitative and Qualitative Disclosures About Market Risk .............. 39 Item 8 -- Financial Statements and Supplementary Data ......................... 39 Item 9 -- Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ....................... 69 PART III Item 10 -- Directors and Executive Officers of the Registrant ................................. 69 Item 11 -- Executive Compensation ..................... 69 Item 12 -- Security Ownership of Certain Beneficial Owners and Management ........... 69 Item 13 -- Certain Relationships and Related Transactions ............................... 69 PART IV Item 14 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K .................... 70 Signatures .............................................. 74 FORWARD LOOKING STATEMENTS We make statements in this report that are considered forward looking statements within the meaning of the Securities Exchange Act of 1934. Sometimes these statements will contain words such as "believes," "expects," "intends," "plans," and other similar words. These statements are not guarantees of our future performance and are subject to risks, uncertainties, and other important factors that could cause our actual performance or achievements to be materially different from those we project. These risks, uncertainties, and factors include, but are not limited to: o general economic, business, and regulatory conditions, o energy supply and demand, o competition, o federal and state regulations, o availability, terms, and use of capital, o nuclear and environmental issues, o weather, o industry restructuring and cost recovery (including the potential effect of stranded investments), o commodity price risk, and o year 2000 readiness. 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 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 OF CONSOLIDATED BUSINESS Baltimore Gas and Electric Company (BGE(R)) is the parent company and conducts our primary business -- the electric and gas utility business. We also conduct diversified businesses in subsidiary companies. BGE was incorporated under the laws of the State of Maryland on June 20, 1906. BGE also owns two-thirds of the outstanding capital stock, including one-half of the voting stock, of Safe Harbor Water Power Corporation (Safe Harbor). Safe Harbor is a producer of hydroelectric power on the Susquehanna River at Safe Harbor, Pennsylvania. We discuss this further in ITEM 2. PROPERTIES -- ELECTRIC. OVERVIEW OF UTILITY BUSINESS Our utility business includes our electric and gas businesses. Our electric business generates, purchases, and sells electricity. Our gas business purchases, transports, and sells natural gas. The focus of these activities is serving residential, commercial, and industrial customers in our service territory. We furnish electric and gas retail services in the City of Baltimore and in all or part of ten counties in Central Maryland. Our electric service territory includes an area of approximately 2,300 square miles with an estimated population of 2.7 million. Our gas service territory includes an area of more than 600 square miles with an estimated population of 2.0 million. There are no municipal or cooperative wholesale customers within our service territory. As discussed throughout this report, the two units at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) are our principal generating facilities and have the lowest fuel cost in our system. An extended outage of either of these units could have a substantial adverse effect on our business and financial condition. We describe prior outages at our nuclear plant in the NUCLEAR OPERATIONS section and in NOTE 10 TO CONSOLIDATED FINANCIAL STATEMENTS. We describe our utility business further in five other sections of this report -- ELECTRIC BUSINESS, ELECTRIC OPERATING STATISTICS, GAS BUSINESS, GAS OPERATING STATISTICS, and FRANCHISES. COMPETITION AND RESPONSE TO REGULATORY CHANGE The electric utility industry is undergoing rapid and substantial change. Competition in the generation part of our business is increasing. In the natural gas industry, competition and regulatory changes are well under way. The regulatory environment (federal and state) for both electric and natural gas is shifting toward customer choice. In response to this change, we regularly reevaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory changes. These strategies might include one or more of the following: o the complete or partial separation of our generation, transmission, and distribution functions, o purchase or sale of generation assets, o mergers or acquisitions of utility or non-utility businesses, o spin-off or sale of one or more businesses, and o growth of earnings from nonregulated businesses. We cannot predict whether any of the strategies described above may actually occur, or what their effect on our financial condition or competitive position might be. Please refer to the FORWARD LOOKING STATEMENTS section. 1 We expect to form a holding company, Constellation Energy Group, Inc., on or about April 30, 1999 and it will be exempt from registration under the Public Utility Holding Company Act of 1935. Maryland law was recently amended to allow public utility companies incorporated in Maryland to form holding companies. We have applied for and received approvals to form our holding company with the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC), and the Pennsylvania Public Utility Commission. In addition, we must receive shareholder approval at our annual meeting scheduled for April 16, 1999. In addition, our Board of Directors has a Long-Range Strategy Committee to oversee the development of our long-range strategic goals, and to consider strategic initiatives presented by management. We also recently formed a Corporate Strategy and Development Group, led by a Vice President, that is responsible for evaluating strategic objectives and developing strategy implementation. We discuss competition in our electric and gas businesses in more detail in the ELECTRIC REGULATORY MATTERS AND COMPETITION and GAS REGULATORY MATTERS AND COMPETITION sections. OVERVIEW OF DIVERSIFIED BUSINESSES In the 1980s, we began to diversify our business in response to limited growth in gas and electric sales. Today, we continue to diversify our business in response to regulatory changes in the utility industry. Our diversified businesses engage primarily in energy services. Our energy services businesses include certain subsidiaries of Constellation(R) Enterprises, Inc. and the District Chilled Water General Partnership (ComfortLink(R)), a general partnership in which BGE is a partner. They are: o Constellation Power Source(TM), Inc. -- our wholesale power marketing and trading business, o Constellation Power(TM), Inc. and Subsidiaries -- our power projects business, o Constellation Energy Source(TM), Inc. -- our energy products and services business, o BGE Home Products & Services(TM), Inc. and Subsidiaries -- our home products, commercial building systems, and residential and small commercial gas retail marketing business, and o ComfortLink -- our cooling services business for commercial customers in Baltimore. Constellation Enterprises, Inc. also has two other subsidiaries: o Constellation Investments(TM), Inc. -- our financial investments business, and o Constellation Real Estate Group(TM), Inc. -- our real estate and senior-living facilities business. We describe our diversified businesses in more detail in the DIVERSIFIED BUSINESSES section. REVENUES AND NET INCOME BY OPERATING SEGMENT The percentages of revenues and net income attributable to our electric, gas, and diversified businesses are shown in the tables below. We present information about our operating segments, including certain non-recurring items, in NOTE 2 TO CONSOLIDATED FINANCIAL STATEMENTS.
REVENUES* ----------------------------------------------- ELECTRIC GAS DIVERSIFIED ---------- ----- -------------------------- ENERGY SERVICES OTHER ----------------- ------ 1998 ......... 66% 13% 16% 5% 1997 ......... 66 16 12 6 1996 ......... 70 16 10 4 1995 ......... 76 14 6 4 1994 ......... 76 15 5 4
NET INCOME* ------------------------------------------------------- ELECTRIC GAS DIVERSIFIED ---------- ------- -------------------------------- ENERGY SERVICES OTHER ----------------- ------------ 1998 ......... 85% 9% 13% (7)% 1997 ......... 88 10 10 (8) 1996 ......... 74 11 10 5 1995 ......... 85 7 6 2 1994 ......... 88 6 6 --
- ---------------------- * Reflects the elimination of intercompany transactions. The differences in percentages of revenues and net income for our electric and gas businesses are due to two factors: o our level of investment in each business, and o our fuel costs in each business. Our electric and gas revenues reflect amounts collected for fuel and other operating expenses plus a return on our investment. Our investment for ratemaking purposes in the electric business is $4.7 billion and our investment for ratemaking purposes in the gas business is approximately $707 million. As a result, our electric revenues include a much higher return component than our gas revenues. Also, as shown in our Consolidated Statements of Income in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, our electric fuel costs ("Electric fuel and purchased energy") were 23% of electric revenues in 1998, and our purchased gas costs ("Gas purchased for resale") were 46% of gas revenues in 1998. This means our cost of fuel in relation to our revenues is lower in the electric business than in the gas business. 2 We charge the actual cost of the fuel we use to generate electricity and the net cost of purchases and sales of electricity to customers with no profit to us. The price we charge for natural gas is based on a market based rates incentive mechanism approved by the Maryland PSC . The difference between our actual cost and the price we charge under market based rates does not significantly impact earnings. We discuss market based rates further in the GAS REGULATORY MATTERS AND COMPETITION section. Our electric and gas revenues come from many customers -- residential, commercial, and industrial. Our largest electric customer provides 2.3% of our total electric revenues. Our largest gas customer provides 1.5% of our total gas revenues. As shown in the tables on page 2, the percentages for revenues and net income have historically been about the same for our diversified businesses. However, in 1998 and 1997, the percentages differ for our other diversified businesses because our real estate and senior-living facilities business wrote down its investments in certain real estate projects. These write-downs reduced net income by about $15.4 million in 1998 and $46.0 million in 1997. We discuss these write-downs further in NOTE 3 TO CONSOLIDATED FINANCIAL STATEMENTS. ELECTRIC BUSINESS We get most of our revenues and net income from our electric utility business. We describe this business in several sections below. ELECTRIC REGULATORY MATTERS AND COMPETITION Electric utilities are facing competition on various fronts, including: o the construction of generating units to meet increased demand for electricity, o the sale of electricity in bulk power markets, o competing with alternative energy suppliers, and o electric sales to retail customers. In recent years, federal and state initiatives have promoted the development of competition in the sale of electricity. In general, these initiatives have sought to unbundle the integrated services that electric utilities have traditionally provided and to enable customers to purchase electricity directly from suppliers other than their local utilities. FEDERAL INITIATIVES With the passage of the Energy Policy Act of 1992, there has been a significant increase in the level of competition for the generation and sale of electricity to wholesale customers. The Energy Policy Act reduces barriers to market entry for companies that wish to build, own, and operate electric generating facilities. It also promotes competition by authorizing the FERC to require electric utilities to provide transmission service to other companies for wholesale power transactions. In 1996, the FERC issued an order requiring electric utilities to make the utility transmission systems available to wholesale sellers and buyers of electric energy on a non-discriminatory basis. This means that other companies may use our transmission system to transport electricity to their customers. Also, we are a member of the PJM (Pennsylvania-New Jersey-Maryland) Interconnection, which is an independent system operator that controls and operates electric transmission facilities in our region as an integrated system on a non-discriminatory basis. The PJM provides open access to the transmission facilities of all of its members based on tariffs filed with the FERC. STATE INITIATIVES At the retail level, many states are implementing "customer choice" programs giving electric retail customers the option to choose among energy suppliers. Maryland is considering offering a customer choice program beginning in July 2000. Presently, the single electric utility company that holds the franchise for the area of Maryland where a retail customer lives serves that customer. Under customer choice, we would continue to transmit and deliver electricity; however, the customer could contract to buy the electricity from any willing supplier. From our perspective, this means that transmission and distribution of electricity will remain regulated services and the generation of electricity will become a competitive service. There are many issues associated with moving from a regulated generation market to a competitive generation market. These issues include, among others: o the recovery of stranded investments1 by electric utilities, o adjusting the tax burden so as not to penalize electric utilities' current generating assets in a competitive market, o how to address the needs of low income customers, and o the need to maintain reliable electric service. - ---------------------- 1 Stranded investments are costs a utility would recover under a regulated pricing system, but not a competitive one. Traditionally, utilities have been required to serve all customers in their franchised area while regulators have set the rates customers pay for that service. To meet customers' demand for electricity, utilities have had to build facilities, including generating plants, and enter into contracts to buy power, among other things, all with the approval of the Maryland PSC. Under customer choice, however, the market will set the price for electricity, not regulators. That means if the market price drops below the current regulated price, the utility may not be able to fully recover its investments in facilities or costs under contracts to buy power and, therefore, a portion of these costs would be "stranded." 3 MARYLAND PSC The Maryland PSC also has addressed customer choice, recognizing, however, that legislation is needed to resolve several issues. In a December 1997 order, the Maryland PSC specified the phase-in of customer choice in three increments, with one-third of customers being offered choice in each increment. The three increments are phased-in over two years from July 1, 2000 to July 1, 2002. Also pursuant to the order, in 1998 we participated in a series of hearings and meetings with others to address the issues of customer choice outlined on page 3. On July 1, 1998, we filed our proposal for transition from a regulated electric supply system to one where generation is priced based on a competitive retail electric market. We discuss our proposal in detail in ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS -- COMPETITION AND RESPONSE TO REGULATORY CHANGE. On December 22, 1998, other parties filed their positions in response to our proposal. The Maryland PSC will hold hearings to examine our proposal and the counter-proposals of other parties. In the meantime, settlement negotiations are ongoing. Absent settlement, the Maryland PSC is scheduled to issue an order by October 1, 1999. On September 3, 1998, the Office of People's Counsel (OPC) filed a petition requesting the Maryland PSC to lower our electric base rates. At our request, the Maryland PSC agreed to consolidate any such review of our electric base rates with its review of our electric restructuring transition proposal mentioned above. We filed testimony and exhibits with the Maryland PSC supporting our position that our current electric base rates are justified. On February 5, 1999, other parties, including the OPC, filed testimonies to lower our base rates by as much as $131 million. As a condition of the Maryland PSC's consolidation of these matters, we agreed to make our rates subject to refund effective July 1, 1999 should the Maryland PSC issue a rate reduction order after that date. MARYLAND LEGISLATION Several bills have been introduced in the 1999 Maryland legislative session that would address the customer choice issues discussed under the heading STATE INITIATIVES, in addition to other related issues. These bills resulted from, in part, the Maryland PSC required hearings and meetings held during 1998. The Maryland legislative session runs until mid-April 1999. We cannot predict whether customer choice legislation will be enacted this session or whether or not the Maryland PSC timetable for implementation of customer choice will change. We also cannot predict the ultimate effect competition or regulatory change will have on our earnings. ELECTRIC RATE MATTERS CONSERVATION SURCHARGE The Maryland PSC allows us to include in base rates a component to recover money we have spent on conservation programs. This component is called a "conservation surcharge" and was approved by the Maryland PSC effective July 1, 1992. Under this surcharge, the Maryland PSC limits what our electric business profit can be. If, at the end of the year, we have exceeded our allowed profit, we defer (include as a liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) the excess in that year and we lower the amount of future surcharges to our customers to correct the amount of overage, plus interest. The surcharge is reset on July 1 of each year. We also discuss the surcharge in ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS -- REGULATION BY THE MARYLAND PUBLIC SERVICE COMMISSION POSTRETIREMENT AND POSTEMPLOYMENT BENEFIT COSTS Beginning in 1998, the Maryland PSC authorized us to make some changes in the way we account for postretirement and other postemployment benefit costs. The Maryland PSC authorized us to: o expense all of the increase in annual postretirement benefit costs related to our electric business, and o amortize the regulatory asset for postretirement and other postemployment benefit costs related to our electric business over 15 years. The Maryland PSC authorized us to reflect these benefit cost changes in our current electric base rates starting in 1998. We also discuss this in NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS. ELECTRIC FUEL RATE PROCEEDINGS By law, we are allowed to recover our cost of electric fuel as long as the Maryland PSC finds that, among other things, we have kept the productive capacity of our generating plants at a reasonable level. To do this, the Maryland PSC may perform an evaluation of each outage (other than regular maintenance outages) at our generating plants. The evaluation will determine if we used all reasonable and cost-effective maintenance and operating control procedures to try to prevent the outage. The Maryland PSC, under the Generating Unit Performance Program, measures annually whether we have maintained the productive capacity of our generating plants at reasonable levels. To do this, the program uses a system-wide generating performance target and 4 an individual performance target for each base load generating unit. In fuel rate hearings, actual generating performance adjusted for planned outages will be compared first to the system-wide target. If that target is met, it should mean that the requirements of Maryland law have been met. If the system-wide target is not met, each unit's adjusted actual generating performance will be compared to its individual performance target to determine if the requirements of Maryland law have been met and, if not, to determine the basis for possibly imposing a penalty on BGE. Even if we meet these targets, other parties to fuel rate hearings may still question whether we used all reasonable and cost-effective procedures to try to prevent an outage. If the Maryland PSC decides we were deficient in some way, the Maryland PSC may not allow us to recover the cost of replacement energy. We are required to submit to the Maryland PSC the actual generating performance data for each calendar year 45 days after year-end. The Maryland PSC reviews the performance for each calendar year in the first fuel rate proceeding that is initiated after the data is submitted. We must initiate fuel rate proceedings in any month following a month during which the calculated fuel rate decreased by more than 5% and may initiate fuel rate proceedings in any month following a month during which the calculated fuel rate increased by more than 5%. NUCLEAR OPERATIONS The two units at Calvert Cliffs use the cheapest fuel. As a result, the costs of replacement energy associated with outages at these units can be significant. During 1989 through 1991 we had extended outages at Calvert Cliffs. These outages drove up fuel costs, and resulted in fuel rate proceedings for several years before the Maryland PSC under the Generating Unit Performance Program, as discussed in ELECTRIC RATE MATTERS -- ELECTRIC FUEL RATE PROCEEDINGS. In these proceedings, the Maryland PSC considered whether any portion of the extra fuel costs should be charged to BGE instead of passed on to customers. In December 1996, we settled the proceedings by agreeing not to bill our customers for $118 million of electric replacement energy costs associated with these outages. In 1990, we wrote off $35 million of these costs. In 1996, we wrote off the remaining $83 million plus $5.6 million of related financing charges. We have been able to recover all replacement energy costs for the outages at Calvert Cliffs in 1992, 1993, and 1994. Our performance in 1995 and 1996 is currently being reviewed in a fuel rate proceeding. We established that we exceeded the system-wide target for those years as well as the performance target for both units at Calvert Cliffs for 1995 and for unit 2 in 1996. Under a settlement agreement in the proceeding, we will recover our replacement energy costs for the 1995 and 1996 outages. Performance for 1997 and 1998 will be reviewed when we submit our next fuel rate application. We cannot estimate the amount of replacement energy costs that could be challenged or disallowed in future fuel rate proceedings, but such amounts could be material. The following is a summary of Calvert Cliffs' performance over the last 5 years:
GENERATION CAPACITY FACTOR --------------------- ---------------- MEGAWATT-HOURS (MWH) 1998 ......... 13,326,633 91% 1997 ......... 13,133,441 90% 1996 ......... 12,069,937 82% 1995 ......... 12,940,496 88% 1994 ......... 11,225,977 77%
In 1998, we filed an application with the NRC for 20-year license renewals for both units at Calvert Cliffs. The current operating licenses expire in 2014 for Unit 1 and in 2016 for Unit 2. This is discussed further in ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS -- OTHER MATTERS. ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES We have implemented various programs for use when system operating conditions require a reduction in load. We refer to these programs as active load management programs. These programs include: o customer-owned generation and curtailable service for large commercial and industrial customers, o air conditioning control which is available to residential and commercial customers, and o residential water heater control. We have generally activated these programs on peak summer days. The potential reduction in the summer 1999 peak load from active load management is approximately 480 megawatts (MW). We recover the costs of these load management programs from our customers. Our generation and transmission facilities are connected to those of neighboring utility systems to form the PJM. Under the PJM agreement, we use the interconnected facilities for substantial energy interchange and capacity transactions as well as emergency assistance. In addition, sometimes we enter into short-term capacity transactions to meet PJM obligations. 5 We have an agreement with Pennsylvania Power & Light Company (PP&L) to purchase electricity and capacity (availability to supply electricity) from June 1, 1990 through May 31, 2001. This agreement, which has been accepted by the FERC, is designed to help maintain adequate reserve margins through this decade and provide flexibility in meeting capacity obligations. The PP&L agreement: o entitles us to 5.94% of the electricity output, and net capacity (currently 130 MW), of PP&L's nuclear Susquehanna Steam Electric Station from October 1, 1991 to May 31, 2001, and o enables us to treat a portion of PP&L's capacity as our capacity for purposes of satisfying our installed capacity requirements as a member of the PJM. We are not acquiring an ownership interest in any of PP&L's generating units. PP&L will continue to control, manage, operate, and maintain that station and all other PP&L-owned generating facilities. Our firm capacity purchases at December 31, 1998 represented: o 150 MW of rated capacity of Bethlehem Steel Corporation's Sparrows Point complex, o 57 MW of rated capacity of the Baltimore Refuse Energy Systems Company, and o 130 MW of Susquehanna capacity from PP&L. FUEL FOR ELECTRIC GENERATION Our electric generation by type of fuel and the cost of each fuel in the five-year period 1994-1998 is shown below:
GENERATION BY FUEL TYPE ------------------------------------------------------ 1998 1997 1996 1995 1994 ---------- ---------- ---------- ---------- ---------- Nuclear (a) ................... 44% 44% 40% 43% 39% Coal .......................... 58 59 58 57 56 Oil ........................... 3 1 1 1 3 Hydro & Gas ................... 4 3 4 3 3 -- -- -- -- -- 109 107 103 104 101 Net Interchange Sales ......... (9) (7) (3) (4) (1) ------ ------ ------ ------ ------ 100% 100% 100% 100% 100% ===== ===== ===== ===== ===== AVERAGE COST OF FUEL CONSUMED ((cent) PER MILLION BTU) ------------------------------------------------------ 1998 1997 1996 1995 1994 ---------- ---------- ---------- ---------- ---------- Nuclear (a) ................... 45.45 46.51 47.29 47.22 52.06 Coal .......................... 137.17 140.52 143.80 148.64 148.64 Oil ........................... 243.18 283.61 313.33 267.59 245.28 Hydro & Gas ................... -- -- -- -- --
- ---------------------- (a) Nuclear fuel costs include disposal costs associated with long-term off-site spent fuel storage and shipping, which is currently set by law at one mill per kilowatt-hour of nuclear generation (approximately 10 cents per million Btu), and contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. We discuss this further below. NUCLEAR The supply of fuel for nuclear generating stations includes the: o purchase of uranium concentrates, o conversion to uranium hexafluoride, o enrichment of uranium hexafluoride, and o fabrication of nuclear fuel assemblies. Information is shown below about fuel requirements for Calvert Cliffs Units 1 and 2: Uranium We have, either in inventory or Concentrates: under contract, sufficient quantities of uranium to meet 70% to 80% of our requirements through 2004. Conversion: We have contractual commitments providing for the conversion of uranium concentrates into uranium hexafluoride which will meet approximately 75% of our requirements through 2004.
Enrichment: We have a contract with the U.S. Enrichment Corporation that provided for 100% of our enrichment requirements through 1998, and will provide for approximately 75% of our enrichment requirements in 1999, declining to approximately 50% by 2004. Fuel We have contracted for the Assembly fabrication of fuel assemblies for Fabrication: reloads required through 2013.
The nuclear fuel market is very competitive and we do not anticipate any problem in meeting our requirements beyond these periods. We discuss our expenditures for nuclear fuel in ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS -- CAPITAL RESOURCES. 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 6 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 what the ultimate cost to dispose of the spent fuel will be. However, the 1982 Act assesses a one mill per kilowatt-hour fee on nuclear electricity generated and sold. 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. 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 amount of the costs we will incur as a result of the DOE's failure to meet the 1998 deadline. STORAGE OF SPENT NUCLEAR FUEL -- BGE 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. COSTS 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 facilities. These contributions are generally payable 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 utility service rates as a cost of fuel. Information about the cost of decommissioning is discussed in NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS under the heading "FUEL AND PURCHASED ENERGY COSTS." 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 coal-burning facilities have the following requirements:
ANNUAL COAL REQUIREMENT (TONS) ------------ Brandon Shores (a) Units 1 and 2 (combined) ......... 3,500,000 Crane (b) Units 1 and 2 (combined) ......... 700,000 Wagner (c) Units 2 and 3 (combined) ......... 1,000,000
- ---------------------- Special Coal Restrictions: (a) Sulfur content less than 0.8% (b) Low ash melting temperature (c) Sulfur content no more than 1% Coal deliveries to our coal burning facilities are made by rail and barge. The coal we use is produced from mines located in central and northern Appalachia. We have a 20.99% undivided interest in the Keystone coal-fired generating plant and a 10.56% undivided interest in the Conemaugh coal-fired generating plant. Both of these plants are located in Pennsylvania. The bulk of the annual coal requirements for the Keystone plant is under contract from Rochester and Pittsburgh Coal Company. The Conemaugh plant purchases coal from local suppliers on the open market. OIL Under normal burn practices, our requirements for residual fuel oil amount to approximately 1,000,000 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. GAS We have a firm natural gas transportation entitlement of 3,500 dekatherms (DTH) a day to provide ignition and banking at certain power plants. We purchase gas for electric generation as needed using interruptible transportation arrangements. Some of our gas fired units can use residual fuel oil instead of gas. 7 ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31, --------------------------------------------------------------- 1998 1997 1996 1995 1994 ------------ ------------ ------------ ------------ ----------- Electric Output (In Thousands) -- MWH: Generated ..................................................... 32,372 31,289 30,107 30,548 28,413 Purchased (A) ................................................. 3,496 4,737 7,560 7,403 6,270 ------ ------ ------ ------ ------ Subtotal ................................................... 35,868 36,026 37,667 37,951 34,683 Less Interchange and Other Sales .............................. 5,454 6,224 7,580 8,149 5,684 ------ ------ ------ ------ ------ Total Output ............................................... 30,414 29,802 30,087 29,802 28,999 ====== ====== ====== ====== ====== Power Generated and Purchased at Times of Peak Load (MW) (one hour): Generated by Company .......................................... 5,565 5,472 4,789 5,162 3,384 Net Purchased (A) ............................................. 480 508 1,166 785 2,654 ------ ------ ------ ------ ------ Peak Load (B) .................................................. 6,045 5,980 5,955 5,947 6,038 ====== ====== ====== ====== ====== Annual System Load Factor (%) .................................. 57.4 56.9 57.5 57.2 54.7 Revenues (In Millions) Residential ................................................... $ 948.6 $ 932.5 $ 958.7 $ 955.2 $ 931.7 Commercial .................................................... 912.9 892.6 861.3 879.4 853.0 Industrial .................................................... 211.5 211.9 207.6 208.5 205.6 --------- --------- --------- --------- --------- System Sales .................................................. 2,073.0 2,037.0 2,027.6 2,043.1 1,990.3 Interchange and Other Sales ................................... 120.8 132.7 155.9 167.0 118.0 Other ......................................................... 27.0 22.3 25.5 21.0 19.1 --------- --------- --------- --------- --------- Total ...................................................... $ 2,220.8 $ 2,192.0 $ 2,209.0 $ 2,231.1 $ 2,127.4 ========= ========= ========= ========= ========= Sales (In Thousands) -- MWH: Residential ................................................... 10,965 10,806 11,243 10,966 10,670 Commercial .................................................... 13,219 12,718 12,591 12,635 12,351 Industrial .................................................... 4,583 4,575 4,596 4,591 4,433 --------- --------- --------- --------- --------- System Sales .................................................. 28,767 28,099 28,430 28,192 27,454 Interchange and Other Sales ................................... 5,454 6,224 7,580 8,149 5,684 --------- --------- --------- --------- --------- Total ...................................................... 34,221 34,323 36,010 36,341 33,138 ========= ========= ========= ========= ========= Customers (In Thousands) Residential ................................................... 1,009.1 1,001.0 995.2 988.2 978.6 Commercial .................................................... 106.5 105.9 104.5 103.4 101.9 Industrial .................................................... 4.6 4.5 4.3 4.1 4.0 --------- --------- --------- --------- --------- Total ...................................................... 1,120.2 1,111.4 1,104.0 1,095.7 1,084.5 ========= ========= ========= ========= ========= Average Cost of Fuel Consumed ((cent) per million BTU) ......... 104.05 105.76 108.05 104.78 112.44 ========== ========== ========== ========== ==========
We achieved an all-time peak load of 6,045 megawatts on August 25, 1998. - ---------- (A) Includes purchases from Safe Harbor Water Power Corporation, a hydroelectric company, of which we own two-thirds of the capital stock. (B) We discuss active load management programs that may be activated at times of peak load in ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES. 8 GAS BUSINESS We describe our gas utility business in the sections below. GAS REGULATORY MATTERS AND COMPETITION In recent years, federal and state initiatives have promoted the development of competition in the sale of gas. In general, these initiatives have sought to unbundle the integrated services that gas utilities have traditionally provided and to enable customers to purchase gas directly from suppliers other than their local utilities. Two decades ago, the price of gas was regulated from the original producer and supplier through the sale to the ultimate end-user. Currently, there is no regulation over the wholesale price of natural gas as a commodity, and the federal regulation of interstate transmission has been reduced. We buy all gas that we resell directly from various suppliers (rather than pipeline companies) and arrange separately for transportation and storage. We offer gas for sale to our residential customers on a firm basis, and to our commercial and industrial customers on a firm and interruptible basis. 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 commercial and industrial 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. We also provide delivery service under a pilot program allowing up to 50,000 residential customers to purchase gas from other suppliers. Currently, approximately 50,000 customers participate in the program but all residential customers will be eligible to receive delivery service beginning on November 1, 1999. In addition to the delivery service, we also provide these customers with meter readings, billing, emergency response, regular maintenance, and balancing. Approximately 53% 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 essentially the same as the base rate charged for gas sales. Delivery service customers may choose to purchase gas from several different suppliers, including two of our diversified businesses. 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. 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: o Columbia Gas Transmission Corporation, o CNG Transmission Corporation, and o 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: o Texas Eastern Transmission Corporation, o Columbia Gulf Transmission Company, and o ANR Pipeline Company. We have storage service agreements with: o Columbia Gas Transmission Corporation, o CNG Transmission Corporation, and o ANR Pipeline Company. Our current pipeline firm transportation entitlements to serve our firm loads are 280,553 DTH per day during the winter period and 255,533 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. The gas is subject to a mix of long- and short-term contracts that are managed to provide economic, reliable, and flexible service. We can arrange additional 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 9 at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, we have: o a liquified 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 o a propane air facility with a mined cavern and refrigerated storage facilities with a total storage capacity equivalent to 1,000,000 DTH and a planned daily capacity of 85,000 DTH. We expect to close our refrigerated storage facilities with approximately 500,000 DTH of storage capacity during the summer of 1999. We believe our remaining storage facilities are sufficient to supplement our gas supply during heavy winter demands and temporary emergencies. 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. GAS RATE MATTERS POSTRETIREMENT AND POSTEMPLOYMENT BENEFIT COSTS Beginning in 1998, the Maryland PSC authorized us to make a change in the way we account for postretirement and other postemployment benefit costs. The Maryland PSC authorized us to amortize the regulatory asset for postretirement and other postemployment benefit costs related to our gas business over 15 years. The Maryland PSC adjusted our gas base rates to recover the higher costs starting in 1998. We discuss this also in NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS. WEATHER NORMALIZATION Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly adjustment to our gas base rate revenues to eliminate the effect of abnormal weather patterns on our gas system sales volumes. This means our monthly gas base rate revenues will be based on weather that is considered "normal" for the month and, therefore, will not be affected by actual weather conditions. DELIVERY SERVICE REALIGNMENT CHARGE Effective November 1, 1998, the Maryland PSC allowed us to begin collecting a Delivery Service Realignment Charge in order to recover certain costs associated with the introduction of competition in our gas business. Costs eligible for recovery include: o amounts under pre-existing interstate pipeline capacity contracts, and o approved administrative and system costs to prepare for competition, including customer education and development costs and changes in computer systems. 1997 RATE CASE In February 1998, we reached a settlement with the Maryland PSC for a $16 million increase in our gas base rates related to the application that we filed in 1997. The increase became effective March 1, 1998. 10 GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------ 1998 1997 1996 1995 1994 ------------ ------------ ------------ ------------ ------------ Gas Output (In Thousands) -- DTH: Purchased ............................ 47,972 62,988 70,260 70,391 68,541 LNG Withdrawn from Storage ........... 268 484 904 815 698 Produced ............................. 46 541 784 528 828 ------ ------ ------ ------ ------ Total Output ...................... 48,286 64,013 71,948 71,734 70,067 Delivery service gas (A) ............. 55,608 52,629 45,964 43,854 41,897 Off-system sales (B) ................. 16,724 14,759 9,968 -- -- ------ ------ ------ ------ ------ Total ............................. 120,618 131,401 127,880 115,588 111,964 ======= ======= ======= ======= ======= Peak Day Sendout (DTH) ................ 658,359 765,011 708,966 706,287 761,900 ======= ======= ======= ======= ======= Capability on Peak Day (DTH) .......... 833,000 870,000 870,000 847,000 847,000 Revenues (In Millions) Residential Excluding Delivery Service ......... $ 279.2 $ 321.7 $ 320.1 $ 248.3 $ 262.7 Delivery Service (C) ............... 4.9 0.5 -- -- -- Commercial Excluding Delivery Service ......... 75.6 113.5 125.1 109.9 121.0 Delivery Service ................... 19.4 12.9 7.2 3.7 2.3 Industrial Excluding Delivery Service ......... 8.0 11.4 17.1 16.7 20.2 Delivery Service ................... 16.0 17.2 14.6 16.3 9.6 --------- --------- --------- --------- --------- System sales ......................... 403.1 477.2 484.1 394.9 415.8 Off-system sales ..................... 40.9 37.5 26.6 -- -- Other ................................ 7.2 6.9 6.6 5.6 5.4 --------- --------- --------- --------- --------- Total ............................. $ 451.2 $ 521.6 $ 517.3 $ 400.5 $ 421.2 ========= ========= ========= ========= ========= Sales (In Thousands) -- DTH: Residential Excluding Delivery Service ......... 33,595 39,958 43,784 40,211 40,279 Delivery Service ................... 1,890 205 -- -- -- Commercial Excluding Delivery Service ......... 11,775 18,435 22,698 23,612 23,712 Delivery Service ................... 16,633 12,964 8,755 6,982 6,490 Industrial Excluding Delivery Service ......... 1,412 2,016 2,887 4,102 4,410 Delivery Service ................... 34,798 38,791 36,201 35,925 33,837 --------- --------- --------- --------- --------- System sales ......................... 100,103 112,369 114,325 110,832 108,728 Off-system sales ..................... 16,724 14,759 9,968 -- -- --------- --------- --------- --------- --------- Total ............................. 116,827 127,128 124,293 110,832 108,728 ========= ========= ========= ========= ========= Customers (In Thousands) Residential .......................... 532.5 524.5 516.5 506.8 498.2 Commercial ........................... 39.6 39.3 38.9 38.4 37.9 Industrial ........................... 1.3 1.3 1.3 1.3 1.3 --------- --------- --------- --------- --------- Total ............................. 573.4 565.1 556.7 546.5 537.4 ========= ========= ========= ========= =========
We achieved an all-time peak day sendout of 765,011 DTH on January 18, 1997. - ---------- (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). (C) Residential delivery service represents sales of gas through our Gas Options pilot program that we began in late 1997. We discuss these programs further in the GAS REGULATORY MATTERS AND COMPETITION section. 11 FRANCHISES We have nonexclusive electric and gas franchises to use streets and other highways which 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. The Public Service Commission Law of Maryland has superseded franchise provisions relating to rates. DIVERSIFIED BUSINESSES Our diversified businesses engage primarily in energy services. We also have other diversified businesses that engage in financial investments and develop, own, and manage real estate and senior-living facilities. Our diversified businesses are presented below. ENERGY SERVICES Our Energy Services businesses experience substantial competition from utility companies or their subsidiaries and from other companies. Competition is based on the price of the commodities, services delivered, and the quality and reliability of services provided. POWER MARKETING AND TRADING We formed CONSTELLATION POWER SOURCE, INC. in February 1997 to enter the power marketing and trading business. This business provides power marketing and risk management services to wholesale customers in North America by purchasing and selling electricity, other energy commodities, and related derivative contracts. In March 1998, Constellation Power Source and Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., formed Orion Power Holdings, Inc. (Orion) to acquire electric generating plants in the United States and Canada. Constellation Power Source owns a minority interest in Orion, and has committed to contribute up to $175 million in equity to fund its investment in Orion. Orion has entered into strategic relationships with Constellation Power Source and Constellation Operating Services, Inc., a subsidiary of Constellation Power, Inc. Constellation Power Source has the exclusive right to provide power marketing and risk management services to Orion. Constellation Operating Services has the exclusive right to provide operating and maintenance services to Orion's plants. POWER PROJECTS CONSTELLATION POWER, INC. AND SUBSIDIARIES primarily develop, own, and operate domestic and international power projects and manage power projects owned by Constellation Investments, Inc. DOMESTIC PROJECTS Our power projects business holds up to a 50% ownership interest in 28 energy projects in operation or under construction that account for $466.0 million of assets. All of these projects are either qualifying facilities under the Public Utility Regulatory Policies Act of 1978 or otherwise exempt from the Public Utility Holding Company Act of 1935. Projects totaling approximately $39.8 million of assets are located in the East and $426.2 million of assets are located in the West. Our power projects business also invests in international power projects. These are discussed later in this section. California Power Purchase Agreements Our Domestic-West power projects include $310.6 million invested in 15 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. Under these agreements, the electricity rates change from fixed rates to variable rates beginning in 1996 and continuing through 2000. The projects that already have had rate changes have lower revenues under variable rates than they did under fixed rates. When the remaining projects transition to variable rates, we expect their revenues also to be lower than they are under fixed rates. We discuss these projects further in NOTE 10 TO CONSOLIDATED FINANCIAL STATEMENTS. Our power projects business is pursuing alternatives for some of these power generation projects including: o repowering the projects to reduce operating costs, o changing fuels to reduce operating costs, o renegotiating the power purchase agreements to improve the terms, o restructuring financing to improve existing terms, and o selling its ownership interests in the projects. INTERNATIONAL PROJECTS Constellation Power's business in Latin America: o develops, acquires, owns, and operates power generation projects, and o acquires and owns distribution systems. 12 At December 31, 1998, Constellation Power had invested about $183.4 million in 15 power projects in Latin America. These investments include: o the purchase of a 51% interest in a Panamanian electric distribution company for approximately $90 million in 1998 by an investment group in which subsidiaries of Constellation Power hold an 80% interest, and o approximately $98 million for the purchase of existing electric generation facilities and the construction of an electric generation facility in Guatemala. In the future, Constellation Power expects to expand its power projects business further in both domestic and international projects. ENERGY PRODUCTS AND SERVICES CONSTELLATION ENERGY SOURCE, INC. offers energy products and services designed primarily to provide solutions to the energy needs of mid-sized commercial and industrial customers. These energy products and services include: o wholesale and retail natural gas marketing services, o a full range of heating, ventilation, air conditioning, and energy services, o energy consulting and power-quality services, o services to enhance the reliability of individual electric supply systems, o customized financing alternatives, and o retail electricity as available. HOME PRODUCTS, COMMERCIAL BUILDING SYSTEMS, AND GAS RETAIL MARKETING BGE HOME PRODUCTS & SERVICES, INC. AND SUBSIDIARIES offer services to residential and small commercial customers. These services include: o the sale and service of electric and gas appliances, o home improvements, o the sale and service of heating, air conditioning, plumbing, electrical, and indoor air quality systems, and o natural gas retail marketing beginning in November 1998. COMFORTLINK COMFORTLINK provides cooling services to commercial customers in Baltimore. OTHER DIVERSIFIED BUSINESSES FINANCIAL INVESTMENTS CONSTELLATION INVESTMENTS, INC. engages in financial investments, including: o marketable securities, o financial limited partnerships, and o financial guaranty insurance companies. REAL ESTATE AND SENIOR-LIVING FACILITIES CONSTELLATION REAL ESTATE GROUP, INC. develops, owns, and manages real estate and senior-living facilities, including: o land under development in the Baltimore-Washington corridor, o an entertainment, dining, and retail complex in Orlando, Florida, o a mixed-use planned-unit development, and o beginning in 1998, a 41.9% 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 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. 13 CONSOLIDATED CAPITAL REQUIREMENTS Our business requires a great deal of capital. Our total capital requirements for 1998 were $1,184 million. Of this amount, $627 million was used in our utility operations and $557 million was used in our diversified businesses. We estimate that our total capital requirements for the years 1999 through 2001 to be: o $1,410 million in 1999, o $1,428 million in 2000, and o $1,502 million in 2001. We continuously review and change our capital expenditure programs, so actual expenditures may vary from the estimates for the years 1999 through 2001. 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: o air quality, o water quality, o waste disposal, and o other environmental matters. Some of the regulations require substantial expenditures for additions to our utility plant and the use of more expensive low-sulfur fuels. We cannot precisely estimate the total effect on our facilities and operations of current and future environmental regulations and standards. However, we increased capital expenditures (excluding allowance for funds used during construction) by approximately $91 million during the five-year period 1994-1998 to comply with existing environmental standards and regulations, and we estimate that the future capital expenditures (excluding allowance for funds used during construction) necessary to comply with environmental standards and regulations will be approximately: o $33 million in 1999, o $30 million in 2000, and o $35 million in 2001. CLEAN AIR The Federal Clean Air Act (the Act) regulates health and welfare standards for concentrations of air pollutants. Under the Act, the State of Maryland must set limits on all major sources of these pollutants in the State so that the standards are not exceeded. We have certain limits on our generating units that put us in compliance with existing air quality regulations, as follows: o All of our generating units, except Crane Units 1 and 2, are limited to burning fuel (coal or oil) with a sulfur content of 1% or below. o The Crane Units 1 and 2 are limited to 3.5 pounds per million Btu for sulfur dioxides, which is equivalent to a coal sulfur content of approximately 2.4%. o All units are limited to releasing particulate matter at or below 0.02 grains per standard cubic foot of exhaust gas for oil fired units and 0.03 grains per standard cubic foot for coal-fired units. o Brandon Shores, a newer plant, is subject to more stringent standards for sulfur dioxides (1.2 pounds per million Btu), and nitrogen oxides (0.7 pounds per million Btu). The Clean Air Act of 1990 contains two titles designed to reduce emissions of sulfur dioxides and nitrogen oxides (NOx) from electric generating stations -- Title IV and Title I. Title IV addresses emissions of sulfur dioxides. Compliance is required in two separate phases: o Phase I became effective January 1, 1995. We met the requirements of this phase by installing flue gas desulfurization systems, switching fuels, and retiring some units. o Phase II must be implemented by January 1, 2000. We expect to meet the compliance requirements through some combination of switching fuels and allowance trading. Title I addresses emissions of NOx. The Maryland Department of the Environment (MDE) issued NOx regulations effective June 1, 1998. The MDE regulations require major NOx sources to reduce NOx emissions up to 65% by May 1999. While we are already taking steps to control NOx emissions at our generating plants, we communicated to MDE that we could not install the required technology at our Brandon Shores plant in time to meet the MDE's May 1999 deadline. On June 19, 1998, we filed a lawsuit against MDE in Baltimore challenging these regulations. On February 9, 1999, the court ordered MDE to reissue the regulations with a new compliance date, indicating it was impossible for utilities to meet the May 1999 deadline. We do not anticipate that MDE will appeal the court's decision. The Environmental Protection Agency (EPA) issued a final rule in September 1998 that requires the reduction of NOx emissions up to 85% by 22 states (including Maryland and Pennsylvania). The 22 states 14 must submit plans to the EPA by September 1999 showing how they will meet its new requirements. Based on the MDE and EPA regulations, we currently estimate that the additional controls needed at our generating plants to meet the 65% NOx emission reduction requirements will cost approximately $126 million. Through December 31, 1998, we have spent approximately $21.5 million to meet the 65% reduction requirements. We cannot estimate the cost for the 85% reduction requirements at this time; however, these costs could be material. In July 1997, the EPA published National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. These standards may require increased controls at our fossil generating plants in the future. We cannot estimate the cost of these increased controls at this time because the states, including Maryland, still need to determine what reductions, if any, in pollutants will be necessary to meet the federal standards. WATER The MDE regulates the discharge of waste materials into the waters of the State of Maryland 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 steam electric generating plants. The MDE water quality regulations require us to, among other things, define procedures to determine compliance with State water quality standards. These procedures require extensive studies involving sampling and monitoring of the waters around affected generating plants. The State of Maryland 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 permit requirements for those who generate, transport, store, or dispose of such wastes. The State of Maryland has adopted regulations governing the management of hazardous wastes that are similar to the EPA regulations. We have procedures in place to comply with all applicable EPA and State of Maryland 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 almost all of our coal fly ash and bottom ash as structural fill material in a manner approved by the State of Maryland. Beginning in 1999, we will provide some of our coal fly ash to a processing facility that is designed to recycle it into a new material that can be sold to the construction industry. We sell the remainder of the coal ash to the construction industry for a number of other approved uses. 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. 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, 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 15.42%, could be as much as $4.9 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 15 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 selected the final remedy and determined that we have met all the requirements of the consent orders. After we install additional public water lines, we will have no further obligations under the consent orders at the site. On August 30, 1994, we were named as a defendant in UNITED STATES V. KEYSTONE SANITATION COMPANY, ET AL. The litigation was instituted by the EPA and involved contamination of the Keystone Sanitation Company landfill Superfund site located in Adams County, Pennsylvania. In 1997, BGE and other defendants entered into a settlement with the EPA for an immaterial amount that was submitted to the court for its approval in 1998. 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. Currently, the EPA is investigating potential soil and groundwater contamination. Although our potential liability cannot be estimated, we do not expect such liability to be material based on the limited amount of waste we shipped to the site. 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 dollars were 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. In April 1997 and September 1998, we received information requests from the EPA concerning the 68th Street Dump Site, also known as the Robb Tyler Dump, located in Baltimore, Maryland. This site is not currently listed as a federal Superfund site. However, in January 1999, the EPA proposed that this site be listed as a federal Superfund site. We understand that the EPA has sent information requests to over 70 other parties. Our response to the EPA is that our records do not show that we sent waste to the site. This response is based on reviewing all relevant documents and interviewing employees involved in waste disposal for the Company from 1950 to 1975, which is the period covered by the EPA's inquiry. 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 these former manufacturing sites, which includes reviewing possible actions to remove coal tar. 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, 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 4 TO CONSOLIDATED FINANCIAL STATEMENTS. Through December 31, 1998, we have spent approximately $32 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 16 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, 1998, we employed about 9,400 people. ITEM 2. PROPERTIES We describe our electric and gas business properties separately below. None of the properties used in connection with the operation of our diversified businesses are considered material to BGE. ELECTRIC Our principal electric generating plants are shown below:
GENERATION (MWH) INSTALLED PRIMARY ---------------------------- PLANT LOCATION CAPACITY (MW) FUEL 1998 1997 - ----------------------- ------------------------- ----------------------- -------------- ------------ ------------- (AT DECEMBER 31, 1998) Steam Calvert Cliffs Calvert County, MD 1,675 Nuclear 13,326,633 13,133,441 Brandon Shores Anne Arundel County, MD 1,296 Coal 8,259,725 8,483,339 Herbert A. Wagner Anne Arundel County, MD 1,006 Coal/Oil/Gas 4,108,074 3,399,601 Charles P. Crane Baltimore County, MD 385 Coal 1,995,318 1,942,621 Gould Street Baltimore City, MD 104 Oil 137,560 89,115 Riverside Baltimore County, MD 78 Oil/Gas 46,322 14,480 Jointly Owned -- Steam Keystone Armstrong and Indiana Counties, P.A. 359(A) Coal 2,800,921 2,788,081 Conemaugh Indiana County, PA 181(A) Coal 1,387,837 1,294,234 Combustion Turbine Perryman Harford County, MD 350 Oil/Gas 234,990 106,748 Notch Cliff Baltimore County, MD 128 Gas 29,644 14,024 Westport Baltimore City, MD 121 Gas 20,814 10,236 Riverside Baltimore County, MD 173 Oil/Gas 11,989 8,197 Philadelphia Road Baltimore City, MD 64 Oil 8,021 3,391 Charles P. Crane Baltimore County, MD 14 Oil 2,247 960 Herbert A. Wagner Anne Arundel County, MD 14 Oil 1,665 754 ----- ---------- ---------- Totals 5,948 32,371,760 31,289,222 ===== ========== ==========
- ---------------------- (A) These totals reflect BGE's proportionate interest and entitlement to capacity from Keystone and Conemaugh, which are 2 megawatts of diesel capacity for Keystone and 1 megawatt of diesel capacity for Conemaugh. We also own two-thirds of the outstanding capital stock of Safe Harbor Water Power Corporation, and are currently entitled to 277 megawatts of the rated capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under a Federal Energy Regulatory Commission license which expires in 2030. 17 GAS We own the following propane air and liquefied natural gas facilities: o a liquefied natural gas facility for the liquefication 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 o a propane air facility with a mined cavern and refrigerated storage facilities with a total storage capacity of 1,000,000 DTH and a planned daily capacity of 85,000 DTH. We expect to close our refrigerated storage facilities with approximately 500,000 DTH of storage capacity during the summer of 1999. We believe our remaining storage facilities are sufficient to supplement our gas supply during heavy winter demands and temporary emergencies. GENERAL INFORMATION We own our principal plants and other important units that are located in Maryland including our principal headquarters building in downtown Baltimore. We also lease several properties in our service area which are used for various offices and services. We have electric transmission and electric and gas distribution lines located: o in public streets and highways pursuant to franchises, and o on permanent rights-of-way secured for the most part by grants from owners of the property and for a relatively small part by condemnation. 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. We share the ownership of the properties for the Keystone and Conemaugh plants in Pennsylvania. There are minor liens and easements on the Keystone and Conemaugh properties, but these encumbrances do not materially interfere with our use of the properties. All of our property referred to above is subject to the lien of our mortgage securing our mortgage bonds. We believe that our operating properties are adequately maintained and are in good operating condition. ITEM 3. LEGAL PROCEEDINGS 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 520 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: o the identity of our facilities at which the plaintiffs allegedly worked as contractors, o the names of the plaintiff's employers, and o the date on which the exposure allegedly occurred. To date, seven of these cases were settled before trial for amounts that were immaterial. One trial is currently scheduled for August 1999. The second type is claims by one manufacturer -- Pittsburgh Corning Corp. -- against us and approximately eight others, as third-party defendants. 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. We do not know the specific facts necessary to estimate our potential liability for these claims. The specific facts we do not know include: o the identity of our facilities containing asbestos manufactured by the manufacturer, o the relationship (if any) of each of the individual plaintiffs to us, o the settlement amounts for any individual plaintiffs who are shown to have had a relationship to us, and o 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. 18 NOX EMISSIONS LITIGATION On June 19, 1998, we filed a lawsuit against the MDE in Baltimore City Circuit Court challenging regulations that require major NOx sources to reduce emissions up to 65% by May 1999. While we were already taking steps to control NOx emissions at out generating plants, we communicated to MDE that we could not install the required technology at our Brandon Shores plant in time to meet the 1999 deadline. On February 9, 1999, the court ordered MDE to reissue the regulations with a new compliance date, indicating it was impossible for utilities to meet the May 1999 deadline. We do not anticipate that MDE will appeal the court's decision. See ITEM 1. BUSINESS -- ELECTRIC RATE MATTERS, NUCLEAR OPERATIONS, FUEL FOR ELECTRIC GENERATION, GAS RATE MATTERS, ENVIRONMENTAL MATTERS, and NOTE 10 TO CONSOLIDATED FINANCIAL STATEMENTS for other information about our legal or regulatory proceedings. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. 19 EXECUTIVE OFFICERS OF THE REGISTRANT Executive Officers of BGE at the date of this report are:
OTHER OFFICES OR POSITIONS NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS - ------------------------- ----- ------------------------------------- ------------------------------------------- Christian H. Poindexter 60 Chairman of the Board, President Chairman of the Board and Chief and Chief Executive Officer (A) Executive Officer (Since March 1, 1998) Vice Chairman Edward A. Crooke 60 Vice Chairman of the President and Chief Operating Officer, Board -- BGE; Chairman of the BGE Board, President and Chief President, Chief Operating Officer, and Executive Officer -- Chairman of the Board, Subsidiaries Constellation Enterprises, Inc. (B) President and Chief Operating Officer, (Since March 1, 1998) Utility Operations Charles W. Shivery 53 Chairman, President and President, Constellation Energy Solutions, Chief Executive Officer Inc. Constellation Power Source, Inc. Vice President (Since February 25, 1997) Finance and Accounting, Chief Financial Officer and Secretary Vice President and Treasurer, Corporate Finance Group Robert E. Denton 56 Executive Vice President Senior Vice President, Generation Generation Vice President, Nuclear Energy (Since March 1, 1998) Frank O. Heintz 55 Executive Vice President Vice President, Gas Utility Operations (Since March 1, 1998) Thomas F. Brady 49 Vice President Vice President, Retail Services Corporate Strategy and Vice President, Customer Service and Development Distribution (Since January 1, 1999) Vice President, Customer Service and Accounting David A. Brune 58 Vice President General Counsel Finance and Accounting, Chief Financial Officer and Secretary (Since February 25, 1997) Robert S. Fleishman 45 Vice President General Counsel Corporate Affairs and Associate General General Counsel Counsel -- Regulatory (Since May 1, 1998) Gregory C. Martin 50 Vice President Manager, Customer Service General Services Manager, Customer Accounts (Since November 1, 1997) and Chief Information Officer (Since August 11, 1998) Linda D. Miller 48 Vice President Vice President, Human Resources Management Services (Since May 1, 1998) Manager, Employee Services
- ---------- (A) Chief Executive Officer, Director, and member of the Executive Committee. (B) Director and member of the Executive Committee. Officers of BGE 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. 20 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER MATTERS STOCK TRADING Our common stock is traded under the ticker symbol BGE. 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 26, 1999, there were 69,305 common shareholders of record. DIVIDEND POLICY We pay dividends on our common stock after our Board of Directors declares them. There is no limitation on our paying common stock dividends unless: o we elect to defer interest payments on the 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038, and any deferred interest remains unpaid; or o all dividends (and any redemption payments) due on our 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. Quarterly dividends were declared on the common stock during 1998 and 1997 in the amounts set forth below. COMMON STOCK DIVIDENDS AND PRICE RANGES
1998 1997 ------------------------------------- ------------------------------------- PRICE* PRICE* ------------------------ ------------------------ DIVIDEND DIVIDEND DECLARED HIGH LOW DECLARED HIGH LOW ---------- ----------- ---------- ---------- ---------- ----------- First Quarter .......... $ .41 $ 34 1/8 $ 29 3/4 $ .40 $ 28 $ 26 1/4 Second Quarter ......... .42 32 15/16 29 1/4 .41 27 24 3/4 Third Quarter .......... .42 33 5/8 29 5/16 .41 28 1/16 26 Fourth Quarter ......... .42 35 1/4 30 1/8 .41 34 5/16 25 13/16 ------ ------ Total ................. $ 1.67 $ 1.63 ====== ======
- ---------- * Based on New York Stock Exchange Composite Transactions as reported in THE WALL STREET JOURNAL. 21 Item 6. Selected Financial Data
Compound 1998 1997 1996 1995 1994 Growth - ------------------------------------------------------------------------------------------------------------------------------------ (DOLLAR AMOUNTS IN MILLIONS, EXCEPT PER SHARE AMOUNTS) 5-Year 10-Year Summary of Operations Total Revenues $ 3,358.1 $ 3,307.6 $ 3,153.2 $ 2,934.8 $ 2,783.0 4.14% 5.37% Expenses Other Than Interest and Income Taxes 2,617.0 2,584.0 2,483.7 2,239.1 2,147.7 4.25 5.81 - --------------------------------------------------------------------------------------------------------------- Income From Operations 741.1 723.6 669.5 695.7 635.3 3.75 3.98 Other Income (Expense) 5.7 (52.8) 6.1 8.8 32.3 (22.43) (11.20) - --------------------------------------------------------------------------------------------------------------- Income Before Interest and Income Taxes 746.8 670.8 675.6 704.5 667.6 3.24 3.68 Net Interest Expense 240.9 230.0 198.5 197.0 190.1 4.99 6.87 - --------------------------------------------------------------------------------------------------------------- Income Before Income Taxes 505.9 440.8 477.1 507.5 477.5 2.47 2.47 Income Taxes 178.2 158.0 166.3 169.5 153.9 5.23 6.71 - --------------------------------------------------------------------------------------------------------------- Net Income 327.7 282.8 310.8 338.0 323.6 1.13 0.77 Preferred and Preference Stock Dividends 21.8 28.7 38.5 40.6 39.9 (12.21) (2.95) - --------------------------------------------------------------------------------------------------------------- Earnings Applicable to Common Stock $ 305.9 $ 254.1 $ 272.3 $ 297.4 $ 283.7 2.68 1.11 =============================================================================================================== Earnings Per Share of Common Stock and Earnings Per Share of Common Stock-- Assuming Dilution $ 2.06 $ 1.72 $ 1.85 $ 2.02 $ 1.93 2.17 (1.14) Dividends Declared Per Share of Common Stock $ 1.67 $ 1.63 $ 1.59 $ 1.55 $ 1.51 2.58 2.38 Summary of Financial Condition Total Assets $ 9,195.0 $ 8,900.0 $ 8,678.2 $ 8,419.1 $ 8,145.3 2.86 6.02 =============================================================================================================== Capitalization Long-term debt $ 3,128.1 $ 2,988.9 $ 2,758.8 $ 2,598.2 $ 2,584.9 2.07 5.87 Preferred stock -- -- -- 59.2 59.2 -- -- Redeemable preference stock -- 90.0 134.5 242.0 279.5 -- -- Preference stock not subject to mandatory redemption 190.0 210.0 210.0 210.0 150.0 4.84 6.63 Common shareholders' equity 2,981.5 2,870.4 2,854.7 2,811.2 2,719.0 2.61 4.69 - --------------------------------------------------------------------------------------------------------------- Total Capitalization $ 6,299.6 $ 6,159.3 $ 5,958.0 $ 5,920.6 $ 5,792.6 1.00 4.51 =============================================================================================================== Financial Statistics at Year End Ratio of Earnings to Fixed Charges 2.94 2.78 3.10 3.21 3.14 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Stock Dividends 2.60 2.35 2.44 2.52 2.47 Book Value Per Share of Common Stock $ 19.98 $ 19.44 $ 19.33 $ 19.06 $ 18.43 Number of Common Shareholders (IN THOUSANDS) 69.9 73.7 77.6 79.8 81.5
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT YEAR'S PRESENTATION. 22 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction In Management's Discussion and Analysis, we explain the general financial condition and the results of operations for BGE(R) and its diversified business subsidiaries including: o what factors affect our businesses, o what our earnings and costs were in 1998 and 1997, o why earnings and costs changed from the year before, o where our earnings came from, o how all of this affects our overall financial condition, o what our expenditures for capital projects were in 1996 through 1998, and what we expect them to be in 1999 through 2001, and o where we will get cash for future capital expenditures. As you read Management's Discussion and Analysis, it may be helpful to refer to our Consolidated Statements of Income which present the results of our operations for 1998, 1997, and 1996. In Management's Discussion and Analysis, we analyze and explain the annual changes in the specific line items in the Consolidated Statements of Income. The electric utility industry is undergoing rapid and substantial change. Competition in the generation part of our business is increasing. The regulatory environment (federal and state) is shifting toward customer choice. These matters are discussed briefly in the "Competition and Response to Regulatory Change" section and in Item 1. Business--Electric Regulatory Matters and Competition. In response to this change, we regularly reevaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory change. These strategies might include one or more of the following: o the complete or partial separation of our generation, transmission, and distribution functions, o purchase or sale of generation assets, o mergers or acquisitions of utility or non-utility businesses, o spin-off or sale of one or more businesses, and o growth of earnings from nonregulated businesses. We cannot predict whether any of the strategies described above may actually occur, or what their effect on our financial condition or competitive position might be. Please refer to the "Forward Looking Statements" section. 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 the utility business and for diversified businesses. OVERVIEW Total Earnings per Share of Common Stock 1998 1997 1996 - -------------------------------------------------------------------------------- Utility business $ 1.93 $ 1.94 $ 1.96 Diversified businesses (subsidiaries) .27 .34 .31 - -------------------------------------------------------------------------------- Total earnings per share from operations 2.20 2.28 2.27 Write-off of merger costs (see Note 2) -- (.25) -- Write-downs of real estate investments (see Note 3) (.10) (.31) -- Disallowed replacement energy costs (see Note 10) -- -- (.42) Write-off of energy services investment (see Note 2) (.04) -- -- - -------------------------------------------------------------------------------- Total earnings per share $ 2.06 $ 1.72 $ 1.85 ================================================================================ 1998 Our 1998 total earnings increased $51.8 million, or $.34 per share, compared to 1997. Our total earnings increased mostly because 1997 results reflect our write-off of merger costs, and our real estate and senior-living facilities business' write-down of its investments in two real estate projects, as discussed in the 1997 section below. Our 1998 earnings would have been higher except: o our real estate and senior-living facilities business wrote down its investment in a real estate project, and o we wrote off an energy services investment. In 1998, utility earnings from operations were about the same compared to 1997. We discuss our utility earnings in more detail in the "Utility Business" section. In 1998, diversified business earnings from operations decreased compared to 1997 mostly because of lower earnings from our real estate and senior-living facilities and financial investments 23 businesses. However, we had higher earnings from our power projects and power marketing and trading businesses. We discuss our diversified business earnings in more detail in the "Diversified Businesses" section. We discuss the real estate write-down in the "Other Diversified Businesses" section and the write-off of the energy services investment in the "Other Energy Services" section. 1997 Our 1997 total earnings decreased $18.2 million, or $.13 per share, compared to 1996. Our total earnings decreased because: o we wrote off costs associated with the terminated merger with Potomac Electric Power Company, and o our real estate and senior-living facilities business wrote down its investments in two real estate projects. We discuss the write-off of merger costs in the "Write-Off of Merger Costs" section, and the real estate write-downs in the "Other Diversified Businesses" section. In 1997, utility earnings from operations decreased compared to 1996 mostly because we sold less electricity and gas due to milder weather. In 1997, diversified business earnings from operations increased compared to 1996 mostly because of higher earnings from our power projects and financial investments businesses. Utility Business Before we go into the details of our electric and gas operations, we believe it is important to discuss factors that have a strong influence on our utility business performance: regulation, the weather, other factors including the condition of the economy in our service territory, and competition. Regulation by the Maryland Public Service Commission (Maryland PSC) The Maryland PSC determines the rates we can charge our customers. Our rates consist of a "base rate" and a "fuel rate." The base rate is the rate the Maryland PSC allows us to charge our customers for the cost of providing them service, plus a profit. We have both an electric base rate and a gas base rate. Higher electric base rates apply during the summer when the demand for electricity is the highest. Gas base rates are not affected by seasonal changes. The Maryland PSC allows us to include in base rates a component to recover money spent on conservation programs. This component is called a "conservation surcharge." However, under this surcharge the Maryland PSC limits what our profit can be. If, at the end of the year, we have exceeded our allowed profit, we defer the excess in that year and we lower the amount of future surcharges to our customers to correct the amount of overage, plus interest. In addition, we charge our electric customers separately for the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil) and for the net cost of purchases and sales of electricity (primarily with other utilities). We charge the actual cost of these items to the customer with no profit to us. If these fuel costs go up, the Maryland PSC permits us to increase the fuel rate. If these costs go down, our customers benefit from a reduction in the fuel rate. The fuel rate is impacted most by the amount of electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear fuel is cheaper than coal, gas, or oil. We discuss this in more detail in the "Electric Fuel Rate Clause" section and in Note 1 of the Notes to Consolidated Financial Statements. Changes in the fuel rate normally do not affect earnings. However, if the Maryland PSC disallows recovery of any part of the fuel costs, our earnings are reduced. In 1996, the Maryland PSC disallowed certain fuel costs as discussed in the "Disallowed Replacement Energy Costs" section and in Note 10. We also 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. From time to time, when necessary to cover increased costs, we ask the Maryland PSC for base rate increases. The Maryland PSC holds hearings to determine whether to grant us all or a portion of the amount requested. The Maryland PSC historically has allowed us to increase base rates to recover increased utility plant 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 lower our base rates. We discuss this in more detail in the "Competition and Response to Regulatory Change" section. Weather Weather affects the demand for electricity and gas. Very hot summers and very cold winters increase demand. Mild weather reduces demand. Weather impacts residential sales more than commercial and industrial sales, which are mostly affected by business needs for electricity and gas. 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. 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. 24 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. Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly adjustment to our gas business revenues to eliminate the effect of abnormal weather patterns. We discuss this further in the "Weather Normalization" section. We show the number of cooling and heating degree days in 1998 and 1997, the percentage changes 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 1998 1997 average - --------------------------------------------------------------- Cooling degree days 915 746 836 Percentage change from prior year 22.7% (5.1)% Heating degree days 4,119 4,822 4,783 Percentage change from prior year (14.6)% (6.2)% Other Factors Other factors, aside from weather, impact the demand for electricity and gas. These factors include the "number of customers" and "usage per customer" during a given period. We use these terms later in our discussions of electric and gas operations. In those sections, we discuss how these and other factors affected electric and gas sales during 1998 and 1997. 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. Usage per customer refers to all other items impacting customer sales which 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. Competition and Response to Regulatory Change Our electric and gas businesses are also affected by competition and regulatory changes. We discuss these items for both of our regulated businesses below. Electric Business Electric utilities are facing competition on various fronts, including: o the construction of generating units to meet increased demand for electricity, o the sale of electricity in bulk power markets, o competing with alternative energy suppliers, and o electric sales to retail customers. On July 1, 1998, BGE and all other Maryland investor-owned electric utilities filed with the Maryland PSC their individual proposals for the transition from a regulated electric supply system to one where generation is priced based on a competitive retail electric market. In our plan, we proposed that: o all customers would be able to choose other suppliers or our service, o we would guarantee our service at rates frozen until July 2002. Prices would then be adjusted for inflation until the transition is complete, but not beyond 2008, o customers who choose an alternate supplier would receive a shopping credit. This credit would reduce their BGE bill by the market value of capacity, energy, and other services that we no longer provide those customers, o we would attempt to reduce potentially stranded investments by lowering operating costs and applying all earnings in excess of our authorized rate of return to accelerate the recovery of generation assets. This would lower the generation asset book values toward their competitive market values thereby reducing any potentially stranded investment, o market value of generation assets would be determined by annual independent appraisals beginning in 2002 and continuing through the transition period, o when the difference between the book value and market value of generation assets is within 10%, the transition period would end and a non-bypassable surcharge would be applied to customers' bills to recover the remaining stranded investments over a two- to three-year period, and o net regulatory assets and nuclear decommissioning costs would continue to be collected from customers through the regulated transmission and distribution business. On December 22, 1998, other parties filed their positions in response to our proposal. The counter-proposals contain provisions which, if adopted by the Maryland PSC, could negatively impact our electric business. The Maryland PSC will hold hearings to examine our electric restructuring transition proposal and the counter-proposals of other parties. In the meantime, settlement negotiations are ongoing. Absent settlement, the Maryland PSC is scheduled to issue an order by October 1, 1999. On September 3, 1998, the Office of People's Counsel (OPC) filed a petition requesting the Maryland PSC to lower our electric base rates. At our request, the Maryland PSC agreed to consolidate any such review of our electric base rates with its review of our electric restructuring transition proposal discussed above. We filed testimony and exhibits with the Maryland PSC supporting our position that our current electric base rates are justified. On February 5, 1999, other parties, including the OPC, filed testimonies to lower our base rates by as much as $131 million. As a condition of the Maryland PSC's consolidation of these matters, we agreed to make our rates subject to refund effective July 1, 1999 should the Maryland PSC issue a rate reduction order after that date. 25 We cannot predict the ultimate effect competition or regulatory change will have on our earnings. We discuss competition in our electric business in Item 1. Business--Electric Regulatory Matters and Competition. Gas Business Regulatory change in the natural gas industry is well under way. We discuss competition in our gas business in Item 1. Business--Gas Regulatory Matters and Competition. Effective November 1, 1998, the Maryland PSC allowed us to begin collecting a Delivery Service Realignment Charge to recover certain costs associated with the introduction of competition in our gas business. This is not expected to significantly impact our earnings. UTILITY Business Earnings per Share of Common Stock 1998 1997 1996 - -------------------------------------------------------------------------------- Electric business $ 1.75 $ 1.77 $ 1.75 Gas business .18 .17 .21 - -------------------------------------------------------------------------------- Total utility earnings per share from operations 1.93 1.94 1.96 Write-off of merger costs (see Note 2) -- (.25) -- Disallowed replacement energy costs (see Note 10) -- -- (.42) - -------------------------------------------------------------------------------- Total utility earnings per share $ 1.93 $ 1.69 $ 1.54 ================================================================================ Utility Business Earnings per Share of Common Stock Our 1998 total utility earnings increased $36.1 million, or $.24 per share, from 1997. Our 1997 total utility earnings increased $24.0 million, or $.15 per share, from 1996. We discuss the factors affecting utility earnings below. Electric Operations Electric Revenues The changes in electric revenues in 1998 and 1997 compared to the respective prior year were caused by: 1998 1997 - ------------------------------------------------------------ (In millions) Electric system sales volumes $50.8 $(15.5) Base rates (6.6) 29.2 Fuel rates (8.1) (4.3) - ------------------------------------------------------------ Total change in electric revenues from electric system sales 36.1 9.4 Interchange and other sales (13.2) (23.2) Other 4.6 (3.2) - ------------------------------------------------------------ Total change in electric revenues $27.5 $(17.0) ========================================================== 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 other sales. The percentage changes in our electric system sales volumes, by type of customer, in 1998 and 1997 compared to the respective prior year were: 1998 1997 - -------------------------------------------- Residential 1.5% (3.9)% Commercial 3.9 1.0 Industrial 0.2 (0.4) In 1998, we sold more electricity to residential customers mostly because: o the number of customers increased, o we had hotter summer weather, and o usage per customer increased. We would have sold even more electricity to residential customers except we had milder winter weather in 1998. We sold more electricity to commercial customers mostly because usage per customer increased. We sold about the same amount of electricity to industrial customers as we did in 1997. In 1997, we sold less electricity to residential customers mostly for two reasons: lower usage per customer and milder weather. We sold more electricity to commercial customers mostly because usage per customer increased. We would have sold even more electricity to commercial customers except for milder weather during the year. We sold about the same amount of electricity to industrial customers as we did in 1996. Base Rates In 1998, base rate revenues decreased compared to 1997. Although we sold more electricity in 1998, our base rate revenues decreased because of lower conservation surcharge revenues. In 1997, base rate revenues increased compared to 1996 because of higher conservation surcharge revenues. During 1996, we exceeded our profit limit under the conservation surcharge. As a result, we excluded $28.5 million of our 1996 surcharge billings from revenue. To correct the overage, we lowered the surcharge on our customers' bills over a twelve- month period beginning July 1997 through June 1998. 26 Fuel Rates In 1998, fuel rate revenues decreased compared to 1997. Although we sold more electricity, the fuel rate was lower mostly because we were able to use a less-costly mix of generating plants and electricity purchases. In 1997, fuel rate revenues decreased compared to 1996 mostly because we sold less electricity. Interchange and Other Sales "Interchange and other sales" are sales in the PJM (Pennsylvania-New Jersey-Maryland) Interconnection energy market and to others. The PJM is a regional power pool with members that include many wholesale market participants, as well as BGE and seven other utility companies. We sell energy to PJM members and to others after we have satisfied the demand for electricity in our own system. In 1998 and 1997, interchange and other sales revenues decreased compared to the respective prior year mostly because of lower sales volumes. Electric Fuel and Purchased Energy Expenses 1998 1997 1996 - ----------------------------------------------------------------- (In millions) Actual costs $514.7 $504.5 $539.2 Net recovery (deferral) of costs under electric fuel rate clause (see Note 1) (9.0) 15.2 8.2 Disallowed replacement energy costs (including carrying charges) (see Note 10) -- -- 95.4 - ----------------------------------------------------------------- Total electric fuel and purchased energy expenses $505.7 $519.7 $642.8 - ----------------------------------------------------------------- Actual Costs In 1998, our actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others increased compared to 1997 mostly because we settled a capacity contract with PECO Energy Company. In 1997, our actual costs decreased compared to 1996 mostly for two reasons: we bought less electricity from others as a result of being able to meet demand using the electricity we generated, and we were able to use a less-costly mix of generating plants mostly because we generated more electricity at Calvert Cliffs. Electric Fuel Rate Clause Under the electric fuel rate clause, we defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future. We discuss the calculation of the fuel rate in Note 1. In 1998, our actual costs of fuel and energy were higher than the fuel rate revenues we collected from our customers. In 1997, our actual costs of fuel and energy were lower than the fuel rate revenues we collected from our customers. Disallowed Replacement Energy Costs In December 1996, we settled fuel rate proceedings about extended outages that occurred at Calvert Cliffs from 1989 through 1991. We agreed not to bill our customers for $118 million of electric replacement energy costs associated with the outages. We wrote off a portion of the costs in 1990 and wrote off the remainder in 1996. We discuss this further in Note 10. Gas Operations Gas Revenues The changes in gas revenues in 1998 and 1997 compared to the respective prior year were caused by: 1998 1997 - ----------------------------------------------- (In millions) Gas system sales volumes $(10.8) $(7.3) Base rates 14.2 0.6 Weather normalization 10.1 -- Gas cost adjustments (87.6) (0.2) - ----------------------------------------------- Total change in gas revenues from gas system sales (74.1) (6.9) Off-system sales 1.8 10.9 Other 0.1 0.3 - ----------------------------------------------- Total change in gas revenues $(72.2) $ 4.3 =============================================== Gas System Sales Volumes The percentage changes in our gas system sales volumes, by type of customer, in 1998 and 1997 compared to the respective prior year were: 1998 1997 - ----------------------------------------------- Residential (11.6)% (8.3)% Commercial (9.5) (0.2) Industrial (11.3) 4.4 27 In 1998, we sold less gas to residential and commercial customers mostly for two reasons: milder weather and lower usage per customer. We would have sold even less gas to residential and commercial customers except the number of customers increased. We sold less gas to industrial customers mostly because usage by Bethlehem Steel (our largest customer) and other industrial customers decreased. In 1997, we sold less gas to residential customers mostly for two reasons: lower usage per customer and milder weather. We sold about the same amount of gas to commercial customers as we did in 1996. We sold more gas to industrial customers mostly for two reasons: milder weather caused fewer service interruptions and Bethlehem Steel used more gas. Sometimes we need to interrupt service during periods with the highest demand. Some industrial customers pay reduced rates in exchange for our right to interrupt their service during these periods. We would have sold even more gas to industrial customers except gas usage by industrial customers other than Bethlehem Steel decreased. Base Rates In 1998, base rate revenues increased compared to 1997. Although we sold less gas during 1998, our base rate revenues increased mostly because the Maryland PSC authorized an increase in our base rates effective March 1, 1998. The change in rates will increase our base rate revenues over the twelve-month period from March 1998 through February 1999 by approximately $16 million. In 1997, base rate revenues increased compared to 1996. Although we sold less gas in 1997, our base rate revenues increased because of higher conservation surcharge revenues during the last six months of the year. Weather Normalization Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly adjustment to our gas base rate revenues to eliminate the effect of abnormal weather patterns on our gas system sales volumes. This means our monthly gas base rate revenues will be based on weather that is considered "normal" for the month and, therefore, will not be 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. These clauses operate similar to the electric fuel rate clause described in the "Electric Fuel Rate Clause" section. However, effective October 1996, the Maryland PSC approved a modification of these gas 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, and does not significantly impact earnings. We also discuss this in Note 1. 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 essentially the same as the base rate charged for gas sales and are included in gas system sales volumes. In 1998 and 1997, gas cost adjustment revenues decreased compared to the respective prior year mostly because we sold less gas. Off-System Sales Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas outside our service territory. Off-system gas sales, which occur after we have satisfied our customers' demand, are not subject to gas cost adjustments. The Maryland PSC approved an arrangement for part of the margin from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Changes in off-system sales do not significantly impact earnings. In 1998, off-system gas sales revenues increased compared to 1997 mostly because we sold more gas off-system. In 1997, off-system gas sales revenues increased compared to 1996 mostly because we first began off-system sales of gas in February 1996. Gas Purchased for Resale Expenses 1998 1997 1996 - ------------------------------------------------------------------- (In millions) Actual costs $212.2 $291.6 $295.4 Net recovery (deferral) of costs under gas adjustment clauses (see Note 1) (3.6) 0.5 (11.0) - ------------------------------------------------------------------- Total gas purchased for resale expenses $208.6 $292.1 $284.4 =================================================================== Actual Costs 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 1998 and 1997, actual gas costs decreased compared to the respective prior year mostly because we sold less gas. 28 Gas Adjustment Clauses We charge customers for the cost of gas sold through gas adjustment clauses (determined by the Maryland PSC), as discussed under "Gas Cost Adjustments" earlier in this section. In 1998, actual gas costs were higher than the revenues we collected from our customers. In 1997, actual gas costs were lower than the revenues we collected from our customers. Other Operating Expenses Operations and Maintenance Expenses In 1998, operations and maintenance expenses increased $34.8 million compared to 1997 mostly because of: o higher nuclear costs, o higher employee benefit costs, and o a $6.0 million write-off of contributions to a third party for a low-level radiation waste facility that was never completed. In 1997, operations and maintenance expenses were slightly lower than they were in 1996. Depreciation and Amortization Expenses We describe depreciation and amortization expenses in Note 1. In 1998, depreciation and amortization expenses increased $34.2 million compared to 1997 mostly because: o in October, 1998, the Maryland PSC authorized us to implement new electric depreciation rates retroactive to January 1, 1998, which increased depreciation expense by approximately $13.9 million, o we had more utility plant in service (as our level of plant in service changes, the amount of our depreciation and amortization expense changes), and o we reduced the amortization period for certain computer software beginning in the first quarter of 1998 from five years to three years. In 1997, depreciation and amortization expenses increased $12.7 million compared to 1996 mostly because we had more plant in service. Other Income and Expenses Write-Off of Merger Costs In September 1995, we signed an agreement with Potomac Electric Power Company to merge together into a new company, Constellation Energy (R) Corporation, after all necessary regulatory approvals were received. In December 1997, both companies mutually terminated the merger agreement. Accordingly, in 1997, we wrote off $57.9 million of costs related to the merger. This write-off reduced after-tax earnings by $37.5 million, or $.25 per share. Interest Charges Interest charges represent the interest on our outstanding debt. In 1998, interest charges increased $6.7 million compared to 1997 mostly because we had more debt outstanding. Interest charges would have been higher except interest rates were lower than they were in 1997. In 1997, interest charges increased $23.6 million compared to 1996 mostly for two reasons: we had more debt outstanding and interest rates were higher. Income Taxes In 1998, income taxes increased $20.2 million compared to 1997 because we had higher taxable income from both our utility operations and our diversified businesses. In 1997, income taxes decreased $8.3 million compared to 1996 because we had lower taxable income from both our utility operations and our diversified businesses. Diversified Businesses Our diversified businesses engage primarily in energy services. Our energy services businesses include certain subsidiaries of Constellation(R) Enterprises, Inc. and the District Chilled Water General Partnership (ComfortLink(R)), a general partnership in which BGE is a partner. They are: o Constellation Power Source,(TM) Inc.--our wholesale power marketing and trading business, o Constellation Power,(TM) Inc. and Subsidiaries--our power projects business, o Constellation Energy Source,(TM) Inc.--our energy products and services business, o BGE Home Products & Services,(TM) Inc. and Subsidiaries--our home products, commercial building systems, and residential and small commercial gas retail marketing business, and o ComfortLink--our cooling services business for commercial customers in Baltimore. Constellation Enterprises, Inc. also has two other subsidiaries: o Constellation Investments,(TM) Inc.--our financial investments business, and o Constellation Real Estate Group,(TM) Inc.--our real estate and senior-living facilities business. We describe our diversified businesses in more detail in Item 1. Business-- Diversified Businesses. 29 DIVERSIFIED Business Earnings per Share of Common Stock 1998 1997 1996 - ------------------------------------------------------------------------ Energy services Power marketing and trading $.05 $.00 $-- Power projects .30 .25 .18 Other (.01) (.05) .02 - ------------------------------------------------------------------------ Total energy services earnings per share from operations .34 .20 .20 Other diversified businesses earnings per share from operations (.07) .14 .11 - ------------------------------------------------------------------------ Total diversified business earnings per share from operations .27 .34 .31 Write-downs of real estate investments (see Note 3) (.10) (.31) -- Write-off of energy services investment (.04) -- -- - ------------------------------------------------------------------------ Total earnings per share $ .13 $ .03 $ .31 ======================================================================== Diversified Business Earnings per Share of Common Stock Our 1998 diversified business earnings increased $15.7 million, or $.10 per share, compared to 1997. Our 1997 diversified business earnings decreased $42.2 million, or $.28 per share, compared to 1996. We discuss factors affecting the earnings of our diversified businesses below. Energy Services Power Marketing and Trading In 1998, earnings from our power marketing and trading business increased compared to 1997 mostly because of increased trading activities in 1998 which was Constellation Power Source's first full year of operations. Constellation Power Source uses the mark-to-market method of accounting for its trading activities. We discuss the mark-to-market method of accounting and Constellation Power Source's trading activities in Note 1. As a result of the nature of its trading activities, Constellation Power Source's revenue 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: o the number and size of new transactions, o the magnitude and volatility of changes in commodity prices and interest rates, and o 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 trading activities, and such variations could be material. In 1998, assets and liabilities from energy trading activities increased because of greater trading activity compared to 1997. In March 1998, Constellation Power Source and Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., formed Orion Power Holdings, Inc. (Orion) to acquire electric generating plants in the United States and Canada. Constellation Power Source has a commitment to fund its investment in Orion as discussed further in Note 10. Power Projects In 1998, earnings from our power projects business increased compared to 1997 mostly because Constellation Power recorded a $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. In 1997, earnings increased compared to 1996 mostly because of improved performance of various energy projects. Also, 1996 earnings included $14.6 million (after-tax) for Constellation Power's percentage share of earnings in a partnership. The partnership recognized a gain on the sale of a power purchase agreement. These increases were offset by $16.2 million of after-tax write-offs of investments in certain power projects. We describe our earnings in the partnerships and the write-offs further in Note 3. California Power Purchase Agreements Constellation Power and subsidiaries and Constellation Investments have $310.6 million invested in 15 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. In 1998, earnings from these projects were $41.3 million, or $.28 per share. Under these agreements, the electricity rates change from fixed rates to variable rates beginning in 1996 and continuing through 2000. The projects which already have had rate changes have lower revenues under variable rates than they did under fixed rates. When the remaining projects transition to variable rates, we expect their revenues also to be lower than they are under fixed rates. 30 Our power projects business is pursuing alternatives for some of these projects including: o repowering the projects to reduce operating costs, o changing fuels to reduce operating costs, o renegotiating the power purchase agreements to improve the terms, o restructuring financing to improve existing terms, and o selling its ownership interests in the projects. The California projects that make the highest revenues will transition in 1999 and 2000. The projects which transition in 1999 contributed $10.7 million, or $.07 per share to 1998 earnings, while those changing over in 2000 contributed $24.0 million, or $.16 per share to 1998 earnings. We expect earnings to ultimately decrease by similar amounts beginning in 1999 as these projects transition. We describe these projects in more detail in Note 10. International Projects At December 31, 1998, Constellation Power had invested about $183.4 million in 15 power projects in Latin America compared to $23.5 million invested in Latin America in 1997. These investments include: o the purchase of a 51% interest in a Panamanian electric distribution company for approximately $90 million in 1998 by an investment group in which subsidiaries of Constellation Power hold an 80% interest, and o approximately $98 million for the purchase of existing electric generation facilities and the construction of an electric generation facility in Guatemala. In the future, Constellation Power expects to expand its power projects business further in both domestic and international projects. Other Energy Services In 1998, earnings from our remaining energy services businesses increased compared to 1997 due to improved results from our energy products and services business. Earnings would have been higher except we recorded a $5.5 million after-tax, or $.04 per share, write-off of our investment in, and certain of our product inventory from, an automated electric distribution equipment company. We recorded this write-off because of that company's inability to raise capital and sell its products. In 1997, earnings from our remaining energy services businesses decreased compared to 1996 mostly because of lower earnings from our energy products and services business. Other Diversified Businesses In 1998, earnings from our other diversified businesses decreased compared to 1997 mostly for two reasons: lower earnings from our real estate and senior-living facilities and financial investments businesses. Earnings from our real estate and senior-living facilities business decreased compared to 1997 mostly due to: o a $15.4 million after-tax write-down of its investment in Church Street Station--an entertainment, dining, and retail complex in Orlando, Florida, o lower earnings from various real estate and senior-living facilities projects, and o a $4 million after-tax gain on the sale of two senior- living facilities projects reflected in 1997 results. In addition, in 1998, our real estate and senior-living facilities business exchanged certain assets and liabilities in return for a 41.9% equity interest in Corporate Office Properties Trust (COPT), a real estate investment trust. Earnings from our financial investments business decreased compared to 1997 mostly because of: o better market performance for our investments in 1997, and o a $6 million after-tax gain on the sale of stock held by a financial limited partnership reflected in 1997 results. In 1997, earnings from our other diversified businesses increased compared to 1996 mostly because of increased earnings in our financial investments business from better earnings in trading securities and increased gains from marketable securities. Earnings would have been higher except we had a decrease in earnings from our real estate and senior-living facilities business mostly due to: o a $14.1 million after-tax write-down of the investment in Church Street Station, and o a $31.9 million after-tax write-down of the investment in Piney Orchard--a mixed-use, planned-unit development. We discuss our real estate projects, the write-downs of our real estate projects, the COPT transaction, and our financial investments further in Note 3. 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. Management's current real estate strategy is to hold each real estate project until we can realize a reasonable value for it except for Church Street Station which we intend to sell. Management evaluates strategies for all its businesses, including real estate, on an ongoing basis. We anticipate that competing demands for our financial resources and changes in the utility industry will cause us to evaluate thoroughly all diversified business strategies on a regular basis so we use capital and other resources in a manner that is most beneficial. 31 Financial Condition Cash Flows 1998 1997 1996 - ----------------------------------------------------------- (In millions) Cash provided by (used in): Operating Activities $820.8 $726.0 $701.9 Investing Activities (625.0) (520.8) (567.0) Financing Activities (184.7) (109.3) (91.6) In 1998 and 1997, cash provided by operations increased compared to the respective prior year mostly because of changes in working capital requirements. In 1998, net cash used in investing activities increased compared to 1997 mostly because of the additional investment in international power projects. Cash used in investing would have been higher except for a $33.8 million decrease in utility construction expenditures. In 1997, net cash used in investing activities decreased mostly because of the $79.5 million cash inflow from the sale of real estate properties and the increase in loans collected from real estate projects compared to 1996. Cash used in investing activities would have been lower except for a $12.7 million increase in utility construction expenditures, and $46.5 million increase for our investments in power projects and financial limited partnerships. Total utility construction expenditures, including the allowance for funds used during construction, were $339.4 million in 1998 as compared to $373.2 million in 1997 and $360.5 million in 1996. In 1998, cash used in financing activities increased compared to 1997 mostly because of the repayment of short-term borrowings that matured, sinking fund requirements, and early redemption of higher cost securities. Net cash used would have been higher except we issued more long-term debt and common stock in 1998 compared to 1997. In 1997, cash used in financing activities increased from 1996 mostly because of the repayment of long-term debt and short-term borrowings that matured, sinking fund requirements, and early redemptions of higher cost securities. Net cash used would have been higher except we issued more long-term debt in 1997 compared to 1996. Security Ratings Independent credit-rating agencies rate our fixed-income securities. The ratings indicate the agencies' assessment of our ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how much it will cost us to sell these securities. The better the rating, the lower the cost of the securities to us when we sell them. Our securities ratings at the date of this report are shown in the following table. Standard Moody's Duff & Phelps' & Poors' Investors Credit Rating Group Service Rating Co. - ----------------------------------------------------------------------- Mortgage Bonds AA- A1 AA- Unsecured Debt A A2 A+ Trust Originated Preferred Securities & Preference Stock A- "a2" A - -------------------------------------------------------------------------------- Capital Resources Our business requires a great deal of capital. Our actual capital requirements for the years 1996 through 1998, along with estimated annual amounts for the years 1999 through 2001, are shown in the table on page 33. For the year ended December 31, 1998, our ratio of earnings to fixed charges was 2.94 and our ratio of earnings to combined fixed charges and preferred and preference dividend requirements was 2.60. Investment requirements for 1999 through 2001 include estimates of funding for existing and anticipated projects. We continuously review and modify those estimates. Actual investment requirements may vary from the estimates included in the table on page 33 because of a number of factors including: o regulation, legislation, and competition, o load growth, o environmental protection standards, o the type and number of projects selected for development, o the effect of market conditions on those projects, o the cost and availability of capital, and o the availability of cash from operations. Our estimates are also subject to additional factors. Please see "Forward Looking Statements" section. 32
1996 1997 1998 1999 2000 2001 - ------------------------------------------------------------------------------------------------------------------- (In millions) Utility Business Capital Requirements: Construction expenditures (excluding AFC) Electric $ 219 $ 238 $ 239 $ 285 $ 269 $ 290 Gas 84 89 55 74 70 69 Common 46 38 35 25 20 18 - ------------------------------------------------------------------------------------------------------------------- Total construction expenditures 349 365 329 384 359 377 AFC 10 8 10 11 13 19 Nuclear fuel (uranium purchases and processing charges) 47 44 50 50 50 48 Deferred conservation expenditures 31 27 16 1 -- -- Retirement of long-term debt and redemption of preference stock 184 243 222 341 253 195 - ------------------------------------------------------------------------------------------------------------------- Total utility business capital requirements 621 687 627 787 675 639 - ------------------------------------------------------------------------------------------------------------------- Diversified Business Capital Requirements: Investment requirements 118 156 325 423 480 500 Retirement of long-term debt 52 188 232 200 273 363 - ------------------------------------------------------------------------------------------------------------------- Total diversified business capital requirements 170 344 557 623 753 863 - ------------------------------------------------------------------------------------------------------------------- Total capital requirements $ 791 $1,031 $1,184 $1,410 $1,428 $1,502 ===================================================================================================================
Capital Requirements of Our Utility Business Our estimates of future electric construction expenditures do not include costs to build more generating units. Electric construction expenditures include improvements to generating plants and to our transmission and distribution facilities. They also include estimated costs for replacing the steam generators and extending the operating licenses at Calvert Cliffs. The operating licenses expire in 2014 for Unit 1 and in 2016 for Unit 2. We estimate these Calvert Cliffs costs to be: o $34 million in 1999, o $44 million in 2000, and o $58 million in 2001. We estimate that during the two-year period 2002 through 2003, we will spend an additional $151 million to complete the replacement of the steam generators and extend the operating licenses at Calvert Cliffs. We discuss the license extension process further in the "Calvert Cliffs License Extension" section. If we do not replace the steam generators, we estimate that Calvert Cliffs could not operate for the full term of its current operating licenses. We expect the steam generator replacements to occur during the 2002 refueling outage for Unit 1 and during the 2003 refueling outage for Unit 2. Additionally, our estimates of future electric construction expenditures include the costs of complying with Environmental Protection Agency (EPA) and State of Maryland 65% nitrogen oxides emissions (NOx) reduction regulations as follows: o $29 million in 1999, o $28 million in 2000, o $33 million in 2001, and o $14 million in 2002. We discuss the NOx regulations further in Note 10. Our utility operations provided about 108% in 1998, 105% in 1997, and 96% in 1996 of the cash needed to meet our capital requirements, excluding cash needed to retire debt and redeem preference stock. We will continue to have cash requirements for: o working capital needs including the payments of interest, distributions, and dividends, o capital expenditures, and o the retirement of debt and redemption of preference stock. During the three years from 1999 through 2001, we expect utility operations to provide about 115% of the cash needed to meet our capital requirements, excluding cash needed to retire debt and redeem preference stock. When we cannot meet our utility capital requirements internally, we sell debt and equity securities. We also sell securities when market conditions permit us to refinance existing debt or preference stock at a lower cost. The amount of cash we need and market conditions determine when and how much we sell. Future funding for capital expenditures, the retirement of debt, redemption of preference stock, and payments of interest and dividends is expected to be provided by internally generated funds, commercial paper issuances, available capacity under credit facilities, and/or the issuance of long-term debt, trust securities, or equity. 33 At December 31, 1998, we have the authority from the Federal Energy Regulatory Commission to issue up to $700 million of short-term borrowings. In addition, we maintain $113 million in committed bank lines of credit and we have $100 million in bank revolving credit agreements to support the commercial paper program as discussed in Note 6. Capital Requirements of Our Diversified Businesses Certain of our diversified businesses expect to expand their businesses which will require additional investments. These investment requirements include funding for: o growing our power marketing and trading business, o the development and acquisition of power projects, as well as loans to project entities, o investments in financial limited partnerships, and o funding for construction of cooling system projects. The investment requirements exclude BGE's commitment to contribute up to $175 million in equity to Constellation Power Source, Inc. to fund its investment in Orion Power Holdings, Inc. Our diversified businesses have met their capital requirements in the past through borrowing, cash from their operations, and from time to time equity contributions from BGE. Our diversified businesses plan to raise the cash needed to meet capital requirements in the future through these same methods. BGE Home Products & Services may also meet capital requirements through sales of receivables. If we can get a reasonable value for our real estate projects, additional cash may be obtained by selling real estate projects. The 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 business and market in the "Other Diversified Businesses" section and in the Notes to Consolidated Financial Statements. Our diversified businesses also have revolving credit agreements totaling $270 million to provide additional liquidity for short-term financial needs, including the issuance of up to $135 million of letters of credit. In 1998, a subsidiary of Constellation Enterprises, Inc. issued $157 million of two- and three-year notes to several institutional investors in a private placement offering. In 1997, our diversified businesses issued $289 million of three- and four-year notes. We discuss our short-term borrowings in Note 6 and long-term debt in Note 7. - -------------------------------------------------------------------------------- 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. Please refer to the "Forward Looking Statements" section. We discuss our market risk and the related use of derivative instruments in this section. Interest Rate Risk We are exposed to changes in interest rates as a result of financing through our issuance of variable-rate debt, fixed-rate debt, and preferred and preference securities. 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 1999 2000 2001 2002 2003 Thereafter Total Dec. 31, 1998 - ----------------------------------------------------------------------------------------------------------------------------- (In millions) Long-term debt Variable-rate debt $ 306.5 $ 40.9 $ 75.0 $ 0.9 $ 6.6 $ 278.3 $ 708.2 $ 708.2 Average interest rate 5.59% 5.97% 5.92% 7.79% 6.89% 4.20% 5.11% Fixed-rate debt $ 228.2 $ 485.1 $ 482.8 $ 154.6 $ 286.6 $ 1,329.7 $ 2,967.0 $ 3,076.6 Average interest rate 7.85% 7.16% 7.08% 7.31% 6.51% 6.72% 6.95% Preference Stock Fixed-rate preference stock $ 7.0 $ -- $ -- $ -- $ -- $-- $ 7.0 $ 7.2 Average interest rate 7.85% --% --% --% --% --% 7.85%
34 Commodity Price Risk We are exposed to the impact of market fluctuations in the price and transportation costs of natural gas, electricity, and other trading commodities. Currently, our gas business and energy services businesses use derivative instruments to manage changes in their respective commodity prices. Gas Business Our gas business may enter into gas futures, options, and swaps to hedge its price risk under our market based rates incentive mechanism and our off-system gas sales program. We discuss this further in Note 1. At December 31, 1998, our exposure to commodity price risk for our gas business was not material. Energy Services Businesses With respect to our energy services businesses, Constellation Power Source manages its commodity price risk inherent in its energy trading 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 electricity and related derivative products. These factors include: o seasonal changes in the demand for electricity, o hourly fluctuations in demand due to weather conditions, o available generation resources, o transmission availability and reliability within and between regions, and o procedures used to maintain the integrity of the physical electricity system during extreme conditions. These factors can affect energy commodity and derivative prices in different ways and to different degrees. These effects may vary throughout the country and result from regional differences in: o weather conditions, o market liquidity, o capability and reliability of the physical electricity system, and o 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 from energy trading activities. 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. As of December 31, 1998, Constellation Power Source's value at risk was $6.0 million. Constellation Power Source's calculation includes all assets and liabilities from 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 from energy trading activities. Due to 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. We discuss Constellation Power Source's trading business in the "Power Marketing and Trading" section and in Note 1. The commodity price risk for our remaining energy services businesses was not material. Equity Price Risk We are exposed to price fluctuations in equity markets primarily through our financial investments business and our nuclear decommissioning trust fund. We are required by the Nuclear Regulatory Commission (NRC) to maintain a trust to fund the costs of decommissioning Calvert Cliffs. At December 31, 1998, equity price risk was not material. 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 power projects business. Our power projects business has $183.4 million invested in 15 international power generation and distribution projects as of December 31, 1998. 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, 1998, foreign currency risk was not material. We discuss our international projects in the "Power Projects" section. 35 Other Matters Calvert Cliffs License Extension In 1998, we filed an application for a 20-year license extension for Calvert Cliffs with the NRC to extend its license beyond 2014 for Unit 1 and 2016 for Unit 2. License renewal evaluations focus on age-related issues in long-lived passive components (passive components include buildings, the reactor vessel, piping, ventilation ducts, electric cables, etc.). We must demonstrate that we can ensure that these passive components will continue to perform their intended functions through the renewal period. The NRC will also consider the impact of the 20-year license extension on the environment. We began the license extension process in 1998 because the NRC may not rule on our application until 2002 or 2003. If the NRC denies our application, we must have adequate time to begin replacement power source planning. We cannot predict the timing of, or impact, if any, of the NRC's decision on our financial results. If our application is denied, it could have a material effect on our financial results. Environmental Matters You will find details of our environmental matters in Note 10 and in Item 1. Business--Environmental Matters. These details include financial information. Some of the information is about environmental costs that may be material to our financial results. Year 2000 Readiness Disclosure We have not experienced any significant year 2000 problems to date and we do not expect any significant problems to impair our operations as we transition to the new century. However, due to the magnitude and complexity of the year 2000 issue, even the most conscientious efforts cannot guarantee that every problem will be found and corrected prior to January 1, 2000. We are focusing on critical operating and business systems and expect to have contingency plans in place to deal with any problems, if they should occur. Please refer to "Forward Looking Statements" section. Utility Business We established a year 2000 Program Management Office (PMO). Based on a work plan developed by the PMO, we have targeted the following six key areas: o digital systems (devices with embedded microprocessors such as power instrumentation, controls, and meters), o telecommunications systems, o major suppliers, o information technology applications (our customer, business, and human resources information systems), o computer hardware and software infrastructure, and o contingency plans. Of these areas, digital systems have the most impact on our ability to provide electric and gas service. Telecommunications, major suppliers, and certain information technology applications also impact our ability to provide electric and gas service. Year 2000 Project Phases Our year 2000 project is divided into two phases: o Phase I--initial assessment and detailed analysis, and o Phase II--testing, remediation, certification, and contingency planning. Phase I involves conducting an inventory of all systems and identifying appropriate resources. We have identified the following appropriate resources for each system or piece of equipment: o BGE employees familiar with each system or piece of equipment, o specialized contractors, and o specific vendors. Phase I also includes developing action plans to ensure that the key areas identified above are year 2000 ready. The action plans for each system or piece of equipment include: o our budget, o schedules for Phase I and II, and o our remediation approach--repair, upgrade, replace or retire. In evaluating our risks and estimating our costs, we utilized employees with expertise in each line of business to perform the activities under Phase I. We believe our employees are the most familiar with their systems or equipment and therefore will provide a reliable estimate of our risks and costs. Phase II includes converting and testing all of our systems. Each system will be tested by those employees used in Phase I following formal guidelines developed by the PMO. Each system or piece of equipment will then be certified by a tester and the PMO, following testing guidelines developed with the help of outside consultants. We are currently evaluating whether we will have our year 2000 testing independently certified. Phase II also includes identifying our major suppliers and developing contingency plans. We have identified our major suppliers and have assessed their year 2000 readiness through surveys. We are currently following-up with our major suppliers via interviews. Contingency Planning Year 2000 operational contingency planning is underway. Staffing and initial planning was completed in 1998. Contingency plans are expected to be completed, including company-wide training, by September 1999. We are developing contingency plans using the contingency guidelines issued by the Nuclear Energy Institute (which are endorsed by the NRC), the contingency guidelines issued by the North American Electric Reliability Council (NERC), and guidance from consultants. 36 We are also addressing the impact of electric power grid problems that may occur outside of our own electric system. We have started year 2000 electric power grid impact planning through our various electric interconnection affiliations. The PJM interconnection has drafted year 2000 operational preparedness plans and restoration scenarios and will continue to develop these plans during the first half of 1999 in cooperation with NERC. The NERC has started monthly assessments of the electric utility industry to communicate the readiness of the national electric grid for year 2000. The NERC has scheduled two industry-wide tests for 1999. Through the Electric Power Research Institute (EPRI), an industry-wide effort has been established to deal with year 2000 problems affecting digital systems and equipment used by the nation's electric power companies. Under this effort, participating utilities are working together to assess specific vendors' system problems and test plans. The assessment was shared by the industry as a whole to facilitate year 2000 problem solving. BGE has joined the American Gas Association (AGA) in an initiative similar to the one with EPRI to facilitate year 2000 problem solving among gas utilities. The AGA and its affiliates has initiated quarterly assessments of the gas utility industry to communicate the readiness of its members for the year 2000. Current Status The most reasonably likely worst case scenario faced by our utility business is any interruption in providing electric and gas service to our customers. We cannot predict the impact of any interruption on our results of operations, but the impact could be material. The following table shows our estimate as of the date of this report of the percentage completed for Phases I and II and our expected year 2000 readiness target dates for the six key areas: Year 2000 readiness Phase I Phase II target date - ---------------------------------------------------------- (approximate % complete) Digital systems 100% 65% June 1999 Telecommunications systems 100% 90% June 1999 Major suppliers 100% 90% June 1999 Information technology applications 100% 70% June 1999 Computer hardware and software infrastructure 100% 85% June 1999 Contingency plans -- 30% September 1999 The completion percentages listed above are reviewed by our PMO in monthly status meetings with the personnel responsible for each project and their supervision. Monthly progress is also monitored by senior BGE management. Costs In the following table, we show the breakdown of our total costs between normal system replacements that will be capitalized (included in the Consolidated Balance Sheets) and the costs that will be expensed (included in our Consolidated Statements of Income) through operations and maintenance (O&M) cost. We also show the breakdown of non-incremental (previously included in our information technology budget) and incremental O&M cost: Actual Estimated Cost Costs Total 1996 1997 1998 1999 2000 Costs - -------------------------------------------------------------------------------- (In millions) Total Cost $ 0.1 $1.7 $18.9 $19.5 $2.0 $ 42.2 Less: Capital cost -- -- 7.3 5.7 -- 13.0 - -------------------------------------------------------------------------------- O&M cost 0.1 1.7 11.6 13.8 2.0 29.2 Less: non- incremental O&M cost 0.1 1.7 4.6 7.0 1.0 14.4 - -------------------------------------------------------------------------------- Incremental O&M cost $ -- $ -- $ 7.0 $ 6.8 $1.0 $ 14.8 ================================================================================ The costs incurred in 1996 and 1997 were for Phase I. The costs incurred in 1998 were for Phases I and II. Costs incurred in 1999 and 2000 will be for Phases I and II. In 1998 and 1999, we had and expect to have the equivalent of approximately 110 full-time employees assigned to our year 2000 project. Diversified Businesses Overview Our diversified businesses have established year 2000 task forces to address their year 2000 issues and are completing their initial assessments. As the initial assessments are completed, the businesses have developed, and will be developing, action plans to prepare their systems for the year 2000. Outside consultants have been retained by several of our diversified businesses to help complete the initial assessment and detailed analysis phase, and to assist in the testing, remediation, and certification phase of their year 2000 projects. The action plans developed are similar to those used by our utility business, including a test certification process. All systems are expected to be certified by December 1999. Our diversified businesses are evaluating whether they will have their year 2000 testing independently certified. In evaluating their risks and estimating their costs, our diversified businesses utilized employees with expertise in each line of business to perform initial assessments. We believe our diversified businesses' employees are the most familiar with their systems or equipment and therefore will provide a reliable estimate of our risks and costs. 37 The progress of our diversified businesses' year 2000 projects are reviewed by their year 2000 task forces in monthly status meetings with the personnel responsible for each project and their supervision. Monthly progress is also monitored by senior management for each business and periodic updates are provided to BGE senior management. Contingency Planning Each of our diversified businesses will develop contingency plans, which are expected to be completed by December 1999. Current Status The most reasonably likely worst case scenarios faced by our energy services businesses and our other diversified businesses are discussed below. However, if any of these scenarios actually occurred, the impact is not expected to be material to our consolidated financial results. Energy Services - --------------- The most reasonably likely worst case scenarios for any one of our power projects would be: o a shutdown of the plant's systems (most of which can be manually overridden), o inability of the purchasing utility to take the plant's power, or o lack of fuel. Personnel at each plant are currently assessing their particular year 2000 issues and certain plants have started the testing, remediation, and certification phase of their year 2000 project. For our power marketing and trading business and our energy products and services business, the most reasonably likely worst case scenario would be encountering any Internet access problems with trading partners, transmission service providers, independent operators, power exchanges, and various electronic bulletin boards. Each of these businesses have two Internet service providers and are contracting with a third provider for alternate routing to critical Internet sites necessary to perform day-to-day business functions. Both are currently assessing their year 2000 issues. For our home products and commercial building systems business, the most reasonably likely worst case scenarios would be any interruption in billing customers or renewing maintenance contracts. This business has substantially completed the assessment and detailed analysis phase and has started the testing, remediation, and certification phase of its year 2000 project. Other Diversified Businesses - ---------------------------- The most reasonably likely worst case scenarios for our financial investments business would be a breakdown in the systems of the brokers or safekeeping banks which it uses to trade, or the failure of its investment managers' computer programs that set investment strategy. This business is currently surveying and monitoring the year 2000 readiness of its banks, brokers, and investment managers. For our real estate and senior-living facilities business, the most reasonably likely worst case scenario is a failure of the systems that support the health, safety, and welfare of residents in the senior-living facilities. Personnel at each facility are involved in assessing their particular year 2000 issues. Costs We estimate our total year 2000 costs for our power projects business to be approximately $4.2 million, of which $1.2 million is related to our year 2000 efforts for our Panamanian electric distribution company. The total estimated year 2000 costs for our remaining diversified businesses are approximately $2.8 million. Accounting Standards Issued and Adopted We discuss recently issued and adopted accounting standards in Note 1. 38 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE 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". ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT ACCOUNTANTS To the Shareholders of Baltimore Gas and Electric Company We have audited the consolidated financial statements and the financial statement schedule of Baltimore Gas and Electric Company and Subsidiaries listed in Item 14(a) of this Form 10-K. These financial statements and the financial statement schedule are the responsibility of the Company's Management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by Management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Baltimore Gas and Electric Company and Subsidiaries as of December 31, 1998 and 1997, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. We have also previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheets and statements of capitalization at December 31, 1996, 1995, and 1994, and the related consolidated statements of income, cash flows, common shareholders' equity, and income taxes for each of the two years in the period ended December 31, 1995 (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 included in the Selected Financial Data for each of the five years in the period ended December 31, 1998, appearing on page 22 is fairly stated in all material respects in relation to the financial statements from which it has been derived. /s/ PRICEWATERHOUSECOOPERS LLP - -------------------------------------------------------------------------------- PRICEWATERHOUSECOOPERS LLP Baltimore, Maryland January 15, 1999 39 Consolidated Statements of Income Baltimore Gas and Electric Company and Subsidiaries
YEAR ENDED DECEMBER 31, 1998 1997 1996 - --------------------------------------------------------------------------------------------------------- (In millions, except per share amounts) Revenues Electric $2,219.2 $2,191.7 $2,208.7 Gas 449.4 521.6 517.3 Diversified businesses 689.5 594.3 427.2 - --------------------------------------------------------------------------------------------------------- Total revenues 3,358.1 3,307.6 3,153.2 Expenses Other Than Interest and Income Taxes Electric fuel and purchased energy 505.7 519.7 547.4 Disallowed replacement energy costs (see Note 10) -- -- 95.4 Gas purchased for resale 208.6 292.1 284.4 Operations 554.1 518.3 526.4 Maintenance 177.5 178.5 174.1 Diversified businesses--selling, general, and administrative 550.9 444.9 311.1 Write-downs of real estate investments (see Note 3) 23.7 70.8 -- Depreciation and amortization 377.1 342.9 330.2 Taxes other than income taxes 219.4 216.8 214.7 - --------------------------------------------------------------------------------------------------------- Total expenses other than interest and income taxes 2,617.0 2,584.0 2,483.7 - --------------------------------------------------------------------------------------------------------- Income from Operations 741.1 723.6 669.5 Other Income (Expense) Write-off of merger costs (see Note 2) -- (57.9) -- Allowance for equity funds used during construction 6.3 5.3 6.5 Equity in earnings of Safe Harbor Water Power Corporation 5.0 5.0 4.6 Net other expense (5.6) (5.2) (5.0) - --------------------------------------------------------------------------------------------------------- Total other income (expense) 5.7 (52.8) 6.1 - --------------------------------------------------------------------------------------------------------- Income Before Interest and Income Taxes 746.8 670.8 675.6 Interest Expense Interest charges 247.9 241.2 217.6 Capitalized interest (3.6) (8.4) (15.6) Allowance for borrowed funds used during construction (3.4) (2.8) (3.5) - --------------------------------------------------------------------------------------------------------- Net interest expense 240.9 230.0 198.5 - --------------------------------------------------------------------------------------------------------- Income Before Income Taxes 505.9 440.8 477.1 Income Taxes 178.2 158.0 166.3 - --------------------------------------------------------------------------------------------------------- Net Income 327.7 282.8 310.8 Preferred and Preference Stock Dividends 21.8 28.7 38.5 - --------------------------------------------------------------------------------------------------------- Earnings Applicable to Common Stock $ 305.9 $ 254.1 $ 272.3 ========================================================================================================= Average Shares of Common Stock Outstanding 148.5 147.7 147.6 Earnings Per Common Share and Earnings Per Common Share--Assuming Dilution $2.06 $1.72 $1.85 =========================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME Baltimore Gas and Electric Company and Subsidiaries
YEAR ENDED DECEMBER 31, 1998 1997 1996 - --------------------------------------------------------------------------------------------------------- (In millions) Net Income $ 327.7 $ 282.8 $ 310.8 Other comprehensive gain/(loss), net of taxes 1.2 (0.8) 1.7 - --------------------------------------------------------------------------------------------------------- Comprehensive Income $ 328.9 $ 282.0 $ 312.5 =========================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 40 Consolidated Balance Sheets Baltimore Gas and Electric Company and Subsidiaries
AT DECEMBER 31, 1998 1997 - --------------------------------------------------------------------------------------------------------- (In millions) Assets Current Assets Cash and cash equivalents $ 173.7 $ 162.6 Accounts receivable (net of allowance for uncollectibles of $20.3 and $24.1 respectively) 401.8 419.8 Trading securities 119.7 119.7 Fuel stocks 85.4 87.6 Materials and supplies 145.1 164.2 Prepaid taxes other than income taxes 68.8 65.2 Assets from energy trading activities 160.2 9.4 Other 21.4 27.4 - --------------------------------------------------------------------------------------------------------- Total current assets 1,176.1 1,055.9 - --------------------------------------------------------------------------------------------------------- Investments and Other Assets Real estate projects and investments 353.9 446.8 Power projects 656.8 451.7 Financial investments 198.0 196.5 Nuclear decommissioning trust fund 181.4 145.3 Net pension asset 108.0 113.0 Safe Harbor Water Power Corporation 34.4 34.4 Senior-living facilities 93.5 62.2 Other 115.4 98.7 - --------------------------------------------------------------------------------------------------------- Total investments and other assets 1,741.4 1,548.6 - --------------------------------------------------------------------------------------------------------- Utility Plant Plant in service Electric 6,890.3 6,725.6 Gas 921.3 846.9 Common 552.8 554.1 - --------------------------------------------------------------------------------------------------------- Total plant in service 8,364.4 8,126.6 Accumulated depreciation (3,087.5) (2,843.4) - --------------------------------------------------------------------------------------------------------- Net plant in service 5,276.9 5,283.2 Construction work in progress 223.0 215.2 Nuclear fuel (net of amortization) 132.5 127.9 Plant held for future use 24.3 25.2 - --------------------------------------------------------------------------------------------------------- Net utility plant 5,656.7 5,651.5 - --------------------------------------------------------------------------------------------------------- Deferred Charges Regulatory assets (net) 565.7 597.3 Other 55.1 46.7 - --------------------------------------------------------------------------------------------------------- Total deferred charges 620.8 644.0 - --------------------------------------------------------------------------------------------------------- Total Assets $9,195.0 $8,900.0 =========================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 41 Consolidated Balance Sheets Baltimore Gas and Electric Company and Subsidiaries
AT DECEMBER 31, 1998 1997 - --------------------------------------------------------------------------------------------------------- (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ -- $ 316.1 Current portions of long-term debt and preference stock 541.7 271.9 Accounts payable 249.6 203.0 Customer deposits 35.5 30.1 Accrued taxes 6.5 5.5 Accrued interest 58.6 58.4 Dividends declared 66.1 66.3 Accrued vacation costs 34.7 36.2 Liabilities from energy trading activities 126.2 8.6 Other 45.3 44.3 - --------------------------------------------------------------------------------------------------------- Total current liabilities 1,164.2 1,040.4 - --------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 1,309.1 1,294.9 Postretirement and postemployment benefits 217.0 185.5 Deferred investment tax credits 118.0 126.6 Decommissioning of federal uranium enrichment facilities 30.8 34.9 Other 56.3 58.4 - --------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 1,731.2 1,700.3 - --------------------------------------------------------------------------------------------------------- Capitalization Long-term debt 3,128.1 2,988.9 Redeemable preference stock -- 90.0 Preference stock not subject to mandatory redemption 190.0 210.0 Common shareholders' equity 2,981.5 2,870.4 - --------------------------------------------------------------------------------------------------------- Total capitalization 6,299.6 6,159.3 - --------------------------------------------------------------------------------------------------------- Commitments, Guarantees, and Contingencies--See Note 10 Total Liabilities and Capitalization $9,195.0 $8,900.0 =========================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 42 Consolidated Statements of Cash Flows Baltimore Gas and Electric Company and Subsidiaries
YEAR ENDED DECEMBER 31, 1998 1997 1996 - --------------------------------------------------------------------------------------------------------- (In millions) Cash Flows From Operating Activities Net income $ 327.7 $ 282.8 $ 310.8 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 429.4 396.8 383.1 Deferred income taxes 17.5 7.4 26.0 Investment tax credit adjustments (8.8) (7.5) (7.6) Deferred fuel costs (8.3) 18.3 0.5 Deferred conservation revenues -- -- 28.5 Disallowed replacement energy costs -- -- 95.4 Accrued pension and postemployment benefits 41.6 (18.0) (13.8) Write-off of merger costs -- 57.9 -- Write-downs of real estate investments 23.7 70.8 -- Allowance for equity funds used during construction (6.3) (5.3) (6.5) Equity in earnings of affiliates and joint ventures (net) (54.5) (42.5) (48.3) Changes in assets from energy trading activities (150.8) (9.4) -- Changes in liabilities from energy trading activities 117.6 8.6 -- Changes in other current assets 39.2 (54.7) (88.0) Changes in other current liabilities 56.1 42.6 (4.9) Other (3.3) (21.8) 26.7 - --------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 820.8 726.0 701.9 - --------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Utility construction expenditures (including AFC) (339.4) (373.2) (360.5) Allowance for equity funds used during construction 6.3 5.3 6.5 Nuclear fuel expenditures (50.5) (43.6) (46.8) Deferred conservation expenditures (16.2) (27.1) (31.4) Contributions to nuclear decommissioning trust fund (17.6) (17.6) (25.5) Merger costs -- (20.9) (28.5) Purchases of marketable equity securities (33.3) (23.0) (32.7) Sales of marketable equity securities 32.8 46.5 39.7 Other financial investments 14.6 (0.4) 7.1 Real estate projects and investments 21.5 24.2 (55.3) Power projects (166.2) (44.3) (5.3) Other (77.0) (46.7) (34.3) - --------------------------------------------------------------------------------------------------------- Net cash used in investing activities (625.0) (520.8) (567.0) - --------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 1,962.2 2,719.0 3,970.8 Long-term debt 831.3 622.0 383.2 Common stock 51.8 -- 3.7 Repayment of short-term borrowings (2,278.3) (2,736.1) (3,916.9) Reacquisition of long-term debt (355.2) (343.3) (158.5) Redemption of preference stock (127.9) (104.5) (112.6) Common stock dividends paid (246.0) (239.2) (233.1) Preferred and preference stock dividends paid (21.0) (29.7) (37.0) Other (1.6) 2.5 8.8 - --------------------------------------------------------------------------------------------------------- Net cash used in financing activities (184.7) (109.3) (91.6) - --------------------------------------------------------------------------------------------------------- Net Increase in Cash and Cash Equivalents 11.1 95.9 43.3 Cash and Cash Equivalents at Beginning of Year 162.6 66.7 23.4 - --------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 173.7 $ 162.6 $ 66.7 ========================================================================================================= Other Cash Flow Information Cash paid during the year for: Interest (net of amounts capitalized) $ 236.7 $ 224.2 $ 193.6 Income taxes $ 164.3 $ 171.2 $ 160.1
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. 43 Consolidated Statements of Common Shareholders' Equity Baltimore Gas and Electric Company and Subsidiaries
Accumulated Other Common Stock Retained Comprehensive Total YEARS ENDED DECEMBER 31, 1998, 1997, AND 1996 Shares Amount Earnings Income Amount - --------------------------------------------------------------------------------------------------------- (DOLLAR AMOUNTS IN MILLIONS, NUMBER OF SHARES IN THOUSANDS) Balance at December 31, 1995 147,527 $1,425.8 $1,381.4 $ 4.0 $2,811.2 Net income 310.8 310.8 Dividends declared Preferred and preference stock (38.5) (38.5) Common stock ($1.59 per share) (234.6) (234.6) Common stock issued 140 3.7 3.7 Other 0.4 0.4 Net unrealized gain on securities 2.6 2.6 Deferred taxes on net unrealized gain on securities (0.9) (0.9) - --------------------------------------------------------------------------------------------------------- Balance at December 31, 1996 147,667 1,429.9 1,419.1 5.7 2,854.7 Net income 282.8 282.8 Dividends declared Preference stock (28.7) (28.7) Common stock ($1.63 per share) (240.7) (240.7) Other 3.1 3.1 Net unrealized loss on securities (1.2) (1.2) Deferred taxes on net unrealized loss on securities 0.4 0.4 - --------------------------------------------------------------------------------------------------------- Balance at December 31, 1997 147,667 1,433.0 1,432.5 4.9 2,870.4 Net income 327.7 327.7 Dividends declared Preference stock (21.8) (21.8) Common stock ($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 ========================================================================================================= SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT YEAR'S PRESENTATION. 44 Consolidated Statements of Capitalization Baltimore Gas and Electric Company and Subsidiaries AT DECEMBER 31, 1998 1997 - --------------------------------------------------------------------------------------------------------- (In millions) Long-Term Debt First Refunding Mortgage Bonds of BGE Floating rate series, due April 15, 1999 $ 125.0 $ 125.0 8.40% Series, due October 15, 1999 91.1 91.1 5 1/2% Series, due July 15, 2000 125.0 125.0 8 3/8% Series, due August 15, 2001 122.3 122.3 7 1/4% Series, due July 1, 2002 124.5 124.5 5 1/2% Installment Series, due July 15, 2002 9.1 9.8 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 125.0 125.0 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 125.0 125.0 7 1/2% Series, due April 15, 2023 84.1 100.0 - --------------------------------------------------------------------------------------------------------- Total First Refunding Mortgage Bonds of BGE 1,554.2 1,570.8 - --------------------------------------------------------------------------------------------------------- Other long-term debt of BGE Medium-term notes, Series B 60.0 100.0 Medium-term notes, Series C 116.0 143.0 Medium-term notes, Series D 215.0 225.0 Medium-term notes, Series E 200.0 183.5 Medium-term notes, Series G 140.0 -- Pollution control loan, due July 1, 2011 36.0 36.0 Port facilities loan, due June 1, 2013 48.0 48.0 Adjustable rate pollution control loan, due July 1, 2014 20.0 20.0 5.55% Pollution control revenue refunding loan, due July 15, 2014 47.0 47.0 Economic development loan, due December 1, 2018 35.0 35.0 6.00% Pollution control revenue refunding loan, due April 1, 2024 75.0 75.0 Variable rate pollution control loan, due June 1, 2027 8.8 8.8 - --------------------------------------------------------------------------------------------------------- Total other long-term debt of BGE 1,000.8 921.3 - --------------------------------------------------------------------------------------------------------- Company obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% deferrable interest subordinated debentures of the Company due June 30, 2038 250.0 -- - --------------------------------------------------------------------------------------------------------- Long-term debt of diversified businesses Loans under revolving credit agreements 74.0 22.0 Mortgage and construction loans 8.69% mortgage note, due January 28, 1998 -- 28.4 7.90% mortgage note, due September 12, 2000 8.3 8.6 8.00% mortgage note, due July 31, 2001 0.1 0.1 8.00% mortgage note, due October 30, 2003 1.8 1.6 7.50% mortgage note, due October 9, 2005 -- 9.7 Variable rate mortgage notes and construction loans, due through 2004 149.5 93.5 7.357% mortgage note, due March 15, 2009 5.1 5.5 9.65% mortgage note, due February 1, 2028 9.6 9.7 8.00% mortgage note, due November 1, 2033 5.8 1.2 Unsecured notes 616.0 579.1 - --------------------------------------------------------------------------------------------------------- Total long-term debt of diversified businesses 870.2 759.4 - --------------------------------------------------------------------------------------------------------- Unamortized discount and premium (12.4) (13.7) Current portion of long-term debt (534.7) (248.9) - --------------------------------------------------------------------------------------------------------- Total long-term debt $3,128.1 $2,988.9 - ---------------------------------------------------------------------------------------------------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT YEAR'S PRESENTATION. CONTINUED ON PAGE 46 45 Consolidated Statements of Capitalization Baltimore Gas and Electric Company and Subsidiaries
AT DECEMBER 31, 1998 1997 - ----------------------------------------------------------------------------------------------------------------- (In millions) Preference Stock Cumulative, $100 par value, 6,500,000 shares authorized Redeemable preference stock 7.50%, 1986 Series, 335,000 shares redeemed at $102.50 per share on July 17, 1998; 30,000 shares redeemed at par on October 1, 1998 $ -- $ 36.5 6.75%, 1987 Series, 30,000 shares redeemed at par on April 1, 1998; 395,000 shares redeemed at $102.25 on July 17, 1998 -- 42.5 8.625%, 1990 Series, 130,000 shares redeemed at par on July 1, 1998 -- 13.0 7.85%, 1991 Series, 70,000 shares outstanding and 140,000 shares redeemed at par on July 1, 1998 7.0 21.0 Current portion of redeemable preference stock (7.0) (23.0) - ----------------------------------------------------------------------------------------------------------------- Total redeemable preference stock -- 90.0 - ----------------------------------------------------------------------------------------------------------------- Preference stock not subject to mandatory redemption 7.78%, 1973 Series, 200,000 shares redeemed at $101 per share on July 17, 1998 -- 20.0 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 190.0 210.0 - ----------------------------------------------------------------------------------------------------------------- Common Shareholders' Equity Common stock without par value, 175,000,000 shares authorized; 149,245,641 and 147,667,114 shares issued and outstanding at December 31, 1998 and 1997, respectively. (At December 31, 1998, 166,893 shares were reserved for the Employee Savings Plan and 2,372,531 shares were reserved for the Shareholder Investment Plan.) 1,485.1 1,433.0 Retained earnings 1,490.3 1,432.5 Accumulated other comprehensive income 6.1 4.9 - ----------------------------------------------------------------------------------------------------------------- Total common shareholders' equity 2,981.5 2,870.4 - ----------------------------------------------------------------------------------------------------------------- Total Capitalization $6,299.6 $6,159.3 =================================================================================================================
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH THE CURRENT YEAR'S PRESENTATION. 46 Consolidated Statements of Income Taxes Baltimore Gas and Electric Company and Subsidiaries
YEAR ENDED DECEMBER 31, 1998 1997 1996 - ------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions) Income Taxes Current $169.5 $158.1 $147.9 - ------------------------------------------------------------------------------------------------------------------- Deferred Change in tax effect of temporary differences 14.2 (1.0) 22.0 Change in income taxes recoverable through future rates 3.9 8.0 4.9 Deferred taxes credited (charged) to shareholders' equity (0.6) 0.4 (0.9) - ------------------------------------------------------------------------------------------------------------------- Deferred taxes charged to expense 17.5 7.4 26.0 Investment tax credit adjustments (8.8) (7.5) (7.6) - ------------------------------------------------------------------------------------------------------------------- Income taxes per Consolidated Statements of Income $178.2 $158.0 $166.3 =================================================================================================================== Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes $505.9 $440.8 $477.1 Statutory federal income tax rate 35% 35% 35% - ------------------------------------------------------------------------------------------------------------------- Income taxes computed at statutory federal rate 177.1 154.3 167.0 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 13.6 13.9 12.6 Allowance for equity funds used during construction (2.2) (1.9) (2.3) Amortization of deferred investment tax credits (8.8) (7.5) (7.7) Tax credits flowed through to income (0.3) (0.5) (0.5) Amortization of deferred tax rate differential on regulated activities (2.3) (2.3) (1.9) State income taxes 9.8 6.2 4.1 Other (8.7) (4.2) (5.0) - ------------------------------------------------------------------------------------------------------------------- Total income taxes $178.2 $158.0 $166.3 =================================================================================================================== Effective federal income tax rate 35.2% 35.8% 34.9% AT DECEMBER 31, 1998 1997 - ---------------------------------------------------------------------------------------------- (In millions) Deferred Income Taxes Deferred tax liabilities Accelerated depreciation $1,009.9 $ 953.5 Allowance for funds used during construction 204.5 206.7 Income taxes recoverable through future rates 88.4 89.8 Deferred termination and postemployment costs 32.3 41.1 Deferred fuel costs 4.5 1.5 Leveraged leases 22.6 25.2 Percentage repair allowance 36.8 38.7 Conservation expenditures 18.9 24.5 Energy trading activities 44.0 2.4 Other 182.6 187.7 - ---------------------------------------------------------------------------------------------- Total deferred tax liabilities 1,644.5 1,571.1 - ---------------------------------------------------------------------------------------------- Deferred tax assets Accrued pension and postemployment benefit costs 54.3 37.6 Deferred investment tax credits 41.3 44.3 Capitalized interest and overhead 46.6 44.5 Contributions in aid of construction 45.6 39.7 Nuclear decommissioning liability 22.8 20.8 Energy trading activities 30.9 1.4 Other 93.9 87.9 - ---------------------------------------------------------------------------------------------- Total deferred tax assets 335.4 276.2 - ---------------------------------------------------------------------------------------------- Deferred tax liability, net $1,309.1 $1,294.9 ==============================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 47 Notes to Consolidated Financial Statements Baltimore Gas and Electric Company and Subsidiaries Note 1 Significant Accounting Policies Nature of Our Business Baltimore Gas and Electric Company (BGE) is the parent company and conducts our primary business--the electric and gas utility business. That business serves Baltimore City and all or part of 10 Central Maryland counties. We also conduct various diversified businesses in subsidiary companies. We describe our operating segments in Note 2. 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. Our consolidated financial statements include the accounts of: o BGE, o Constellation Enterprises, Inc. and Subsidiaries, o District Chilled Water General Partnership (ComfortLink), and o BGE Capital Trust I (See Note 7). The Equity Method We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including power projects) where we hold a 20% to 50% voting interest. Under the equity method, we report: o our interest in the entity as an investment in our Consolidated Balance Sheets, and o our percentage share of the earnings from the entity in our Consolidated Statements of Income. The only time we do not use this method is if we can exercise control over the operations and policies of the company. If we have control, accounting rules require us to use consolidation. We report our investment in Safe Harbor Water Power Corporation (Safe Harbor) under the equity method. Safe Harbor is a producer of hydroelectric power. BGE owns two-thirds of Safe Harbor's total capital stock, including one-half of the voting stock, and a two-thirds interest in its retained earnings. 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) regulates our utility business. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under generally accepted accounting principles. 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 4. 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 regulated assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery. At December 31, 1998, we met the requirements of SFAS No. 71. We discuss our transition proposal for electric utility competition filed with the Maryland PSC in the "Competition and Response to Regulatory Change" section of Management's Discussion and Analysis. 48 Utility Revenues We record utility revenues in our Consolidated Statements of Income when we provide service to customers. Fuel and Purchased Energy Costs We incur costs for: o the fuel we use to generate electricity, o purchases of electricity from others, and o natural gas that we resell. These costs are shown in our Consolidated Statements of Income as "Electric fuel and purchased energy" and "Gas purchased for resale." We discuss each of these separately below. Fuel Used to Generate Electricity and Purchases of Electricity From Others Under the electric fuel rate clause set by the Maryland PSC, we charge our electric customers for: o the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil), and o the net cost of purchases and sales of electricity (primarily with other utilities). We charge the actual costs of these items to customers with no profit to us. To do this, we must keep track of what we spend and what we collect from customers under the fuel rate in a given period. Usually these two amounts are not the same because there is a difference between the time we spend the money and the time we collect it from our customers. Under the electric fuel rate clause, we defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate in a given period. We either bill or refund our customers that difference in the future. We discuss this further in Note 4. We calculate the electric fuel rate using three factors: o the mix of generating plants we used over the last 24 months, o the latest three-month average fuel cost for each generating unit, and o the net cost of purchases and sales of electricity over the last 24 months. We may change the fuel rate only if the calculated rate is more than 5% above or below the rate in effect. The fuel rate is affected most by the amount of electricity generated at our Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) because the cost of nuclear fuel is cheaper than coal, gas, or oil. We also report two other items as "Electric fuel and purchased energy" in our Consolidated Statements of Income: o amortization of nuclear fuel (described under "Utility Plant" later in this note). We amortize nuclear fuel based on the energy produced over the life of the fuel. We pay quarterly fees to the Department of Energy for the future disposal of spent nuclear fuel, and accrue these fees based on the kilowatt-hours of electricity sold. We bill our customers for nuclear fuel as described earlier in this note, and o amortization of deferred costs of decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. We discuss these costs further in Note 4. Extended outages at Calvert Cliffs increase fuel costs and may result in fuel rate proceedings before the Maryland PSC. In these proceedings, the Maryland PSC would consider whether any portion of the extra fuel costs should be paid by BGE instead of passed on to customers. We discuss the financial impact of past extended outages in Note 10. 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, effective October 1996, 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 engage in risk management activities in our gas business and in our diversified businesses. We separately describe these activities for each business below. 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. 49 Our gas business internal guidelines do not permit the use of swap agreements for any other purpose than to hedge price risk. We defer, as unrealized gains or losses, the net amount we are due (unrealized gains) or owe (unrealized losses) under the swap agreements 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. Diversified Businesses 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 uses the mark-to-market method of accounting for its trading activities. Under the mark-to-market method of accounting, we report: o 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 o changes in fair value as components of "Diversified business revenues" in our Consolidated Statements of Income. 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 1996 current income tax expense amount includes alternative minimum tax credits of $30 million. The alternative minimum tax can be carried forward indefinitely and used as tax credits in years when our regular tax liability exceeds the alternative minimum tax liability. We do not have any remaining alternative minimum 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 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 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 diversified 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 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 or payable through future rates." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further in Note 4. Franchise Taxes We pay Maryland public service company franchise tax instead of state income tax on our utility revenue from sales in Maryland. We include the franchise tax in "Taxes other than income taxes" in our Consolidated Statements of Income. 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: o land under development in the Baltimore-Washington corridor, o an entertainment, dining, and retail complex in Orlando, Florida, o a mixed-use planned-unit development, o senior-living facilities, and o beginning in 1998, a 41.9% 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. 50 Evaluation of Assets for Impairment 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 utility 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. 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 below. We report investments that are not covered by SFAS No. 115 at their cost. Trading Securities Our diversified 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 "Diversified business 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 diversified 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. We also include our diversified businesses' portion of unrealized gains or losses on securities of equity-method (described earlier in this note) investees in our Consolidated Statements of Common Shareholders' Equity. Utility Plant, Depreciation, Amortization, and Decommissioning Utility Plant Utility plant is the term we use to describe our utility business property and equipment that is in use, being held for future use, or under construction. We summarize utility plant in our Consolidated Balance Sheets. We report our utility plant at its original cost, which includes: o material and labor, o contractor costs, o construction overhead costs (where applicable), and o an allowance for funds used during construction (described later in this note). We charge retired or otherwise-disposed-of utility plant to accumulated depreciation. 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 $152 million at December 31, 1998 and 1997. We report these properties in the same accounts we use for our other utility plant (described above). Depreciation Expense Generally, we compute depreciation by applying composite, straight-line rates (approved by the Maryland PSC) to the average investment in classes of depreciable property. We depreciate vehicles based on their estimated useful lives. 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. 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 record decommissioning expense based on a facility-specific cost estimate so we can accumulate a decommissioning reserve of $521.0 million in 1993 dollars by the end of Calvert Cliffs' service life in 2016, adjusted to reflect expected inflation. We have reported the decommissioning reserve in "Accumulated depreciation" in our Consolidated Balance Sheets. The total reserve was $244.0 million at December 31, 1998 and $201.6 million at December 31, 1997. 51 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. Allowance for Funds Used During Construction and Capitalized Interest Allowance for Funds Used During Construction (AFC) We finance 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 plant is placed in service. The AFC rates are 9.04% for gas plant, 9.36% for common plant, and 9.40% for electric plant. We compound AFC annually. Capitalized Interest Our diversified businesses capitalize interest costs incurred to finance real estate developed for internal use and certain power projects. 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, we amortize those gains or losses over the remaining original life of the debt. Cash Flows For the purpose of reporting our cash flows, we define cash equivalents as highly liquid investments that mature in three months or less. Use of Accounting Estimates Management makes estimates and assumptions when preparing financial statements under generally accepted accounting principles. These estimates and assumptions affect various matters, including: o our reported amounts of assets and liabilities in our Consolidated Balance Sheets at the dates of the financial statements, o our disclosure of contingent assets and liabilities at the dates of the financial statements, and o our reported amounts of revenues and expenses in our Consolidated Statements of Income during the reporting periods. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual amounts could differ from these estimates. Reclassifications We have reclassified certain prior-year amounts for comparative purposes. These reclassifications did not affect consolidated net income for the years presented. Accounting Standards Adopted We adopted SFAS No. 130, Reporting Comprehensive Income, effective January 1, 1998. Comprehensive income includes net income plus all changes in shareholders' equity for the period, excluding shareholder transactions (some examples are stock issuances and dividend payments). Our comprehensive income includes net income plus the effect of unrealized gains or losses on available-for-sale securities. We have presented comprehensive income in the Consolidated Statements of Comprehensive Income, and accumulated other comprehensive income in the Consolidated Statements of Common Shareholders' Equity and in the Consolidated Statements of Capitalization. We adopted SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information, effective January 1, 1998. SFAS No. 131 establishes standards for the way that we report information about operating segments in annual financial statements and requires that we report selected information about operating segments in interim financial reports. SFAS No. 131 also establishes standards for related disclosures about products and services, geographic areas, and major customers. The adoption of this statement did not affect results of operations or financial position, but did affect the disclosure of segment information. See Note 2. 52 We adopted SFAS No. 132, Employers' Disclosures about Pensions and Other Postretirement Benefits, effective January 1, 1998. SFAS No. 132 establishes standards for the way that we report our pension and postretirement benefits as well as requiring additional information on changes in the benefit obligations and fair values of plan assets. The adoption of this statement did not affect results of operations or financial position, but did affect the disclosure of pension and postretirement benefits information. See Note 5. Accounting Standards Issued In March 1998, the American Institute of Certified Public Accountants (AICPA) issued Statement of Position (SOP) 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. SOP 98-1 establishes the accounting for the costs of computer software developed or obtained for internal use. We must adopt the requirements of this statement in our financial statements for the year ending December 31, 1999. In April 1998, the AICPA issued SOP 98-5, Reporting on the Costs of Start-up Activities. SOP 98-5 establishes the accounting for the costs of start-up activities. We must adopt the requirements of this statement in our financial statements for the year ending December 31, 1999. We do not expect the adoption of these statements to have a material impact on our financial results. 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. We must adopt the requirements of this standard beginning with our financial statements for the quarter ending March 31, 2000. We have not determined the effects of SFAS No. 133 on our financial results. In November 1998, the EITF reached a consensus on EITF 98-10, Accounting for Energy Trading and Risk Management Activities, requiring that energy trading activities be accounted for on a mark-to-market basis. We must adopt the requirements of this consensus in our financial statements for the year ending December 31, 1999. We do not expect the adoption of this consensus to have a material impact on our financial results. - -------------------------------------------------------------------------------- Note 2 Information by Operating Segment We have three reportable operating segments: Electric, Gas, and Energy Services: o our Electric business generates, purchases, and sells electricity, o our Gas business purchases, transports, and sells natural gas, and o our Energy Services businesses consist of certain diversified businesses that: -- engage in power projects, -- provide marketing and risk management services, -- sell natural gas through mass marketing efforts, sell and service electric and gas appliances, heating and air conditioning systems, and engage in home improvements, and -- provide cooling services to commercial customers in Baltimore. Our remaining diversified businesses: o engage in financial investments, and o 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. The segments have the same accounting policies as those described in the summary of significant accounting policies in Note 1. 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 page 54. 53
Energy Other Unallocated Electric Gas Services Diversified Corporate Business Business Businesses Businesses Items (A) Eliminations Consolidated - --------------------------------------------------------------------------------------------------------------------------- (In millions) 1998 Unaffiliated revenues $2,219.2 $449.4 $ 524.1 $165.4 $ -- $ -- $3,358.1 Intersegment revenues 1.6 1.7 12.0 0.5 -- (15.8) -- - --------------------------------------------------------------------------------------------------------------------------- Total revenues 2,220.8 451.1 536.1 165.9 -- (15.8) 3,358.1 Depreciation and amortization 313.0 45.4 9.2 9.3 0.2 -- 377.1 Equity in earnings of equity- method investees (B) 5.0 -- -- -- -- -- 5.0 Net interest expense 164.9 23.6 16.0 38.6 (1.9) (0.3) 240.9 Income tax expense (benefit) 146.6 13.4 34.1 (15.8) (0.1) -- 178.2 Net income (loss) (C) 278.7 28.8 43.4 (24.2) (0.1) 1.1 327.7 Segment assets 6,342.8 934.6 1,235.0 811.6 (14.0) (115.0) 9,195.0 Utility construction expenditures 279.0 60.4 -- -- -- -- 339.4 1997 Unaffiliated revenues $2,191.7 $521.6 $ 399.4 $194.9 $ -- $ -- $3,307.6 Intersegment revenues 0.3 -- 0.6 9.7 -- (10.6) -- - --------------------------------------------------------------------------------------------------------------------------- Total revenues 2,192.0 521.6 400.0 204.6 -- (10.6) 3,307.6 Depreciation and amortization 286.5 39.3 6.9 9.9 0.3 -- 342.9 Equity in earnings of equity- method investees (B) 5.0 -- -- -- -- -- 5.0 Net interest expense 160.7 20.3 10.1 32.5 6.4 -- 230.0 Income tax expense (benefit) 135.7 13.9 23.8 (13.5) (1.9) -- 158.0 Net income (loss) (D) 249.6 28.8 27.4 (21.1) (3.6) 1.7 282.8 Segment assets 6,404.4 907.7 700.9 885.4 10.7 (9.1) 8,900.0 Utility construction expenditures 278.7 94.5 -- -- -- -- 373.2 1996 Unaffiliated revenues $2,208.7 $517.3 $ 313.3 $113.9 $ -- $ -- $3,153.2 Intersegment revenues 0.3 -- 1.0 5.8 -- (7.1) -- - --------------------------------------------------------------------------------------------------------------------------- Total revenues 2,209.0 517.3 314.3 119.7 -- (7.1) 3,153.2 Depreciation and amortization 279.3 37.8 3.2 9.6 0.3 -- 330.2 Equity in earnings of equity- method investees (B) 4.6 -- -- -- -- -- 4.6 Net interest expense 150.6 17.5 7.2 24.4 (1.2) -- 198.5 Income tax expense (benefit) 121.7 16.0 23.8 8.9 (4.1) -- 166.3 Net income (loss) (E) 230.9 33.9 30.6 16.8 (1.7) 0.3 310.8 Segment assets 6,466.5 826.8 485.5 901.4 11.0 (13.0) 8,678.2 Utility construction expenditures 262.5 98.0 -- -- -- -- 360.5
(A) A holding company for our diversified businesses does not allocate the items presented in the table to our Energy Services and Other Diversified businesses. (B) Our Energy Services and our Other Diversified businesses record their equity in earnings of equity-method investees in their unaffiliated revenues. (C) Our Energy Services businesses recorded $10.4 million for its share of earnings in a partnership as discussed in Note 3 and a $5.5 million write-off of an energy services investment as discussed in the "Other Energy Services" section of Management's Discussion and Analysis. In addition, our Other Diversified businesses recorded a $15.4 million write-down of a real estate project as discussed in Note 3. (D) Our Electric business recorded a $37.5 million write-off related to the terminated merger with Potomac Electric Power Company as discussed in the "Write-Off of Merger Costs" section of Management's Discussion and Analysis. In addition, our Other Diversified businesses recorded a $46.0 million write-down of two real estate projects as discussed in Note 3. (E) Our Electric business recorded a $62.1 million write-off of electric replacement energy costs as discussed in Note 10. In addition, our Energy Services businesses recorded $14.6 million for its share of earnings in a partnership and $16.2 million of write-offs of several power projects as discussed in Note 3. 54 Note 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, 1998 1997 - --------------------------------------------------------- (In millions) Properties under development $210.6 $220.8 Rental and operating properties (net of accumulated depreciation) 38.9 225.6 Equity interest in real estate investment trust 104.0 -- Other real estate ventures 0.4 0.4 - --------------------------------------------------------- Total real estate projects and investments $353.9 $446.8 ========================================================= In 1998, CREG recorded a $15.4 million after-tax write-down of the investment in Church Street Station--an entertainment, dining, and retail complex in Orlando, Florida--which occurred because the fair value of the project has declined based upon recent competitive bids. CREG is attempting to sell this complex during 1999. In 1998, CREG entered into an agreement with Corporate Office Properties Trust (COPT), a real estate investment trust based in Philadelphia. Under the terms of the agreement, 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 being acquired by COPT. These options and first refusal rights have terms that range from 2-5 years. By July 1999, COPT is expected to acquire one retail property from CREG for approximately $3.5 million in cash, unless that property is sold to another party prior to that time. In 1997, CREG recorded the following write-downs of real estate projects: o a $14.1 million after-tax write-down of the investment in Church Street Station--which occurred because CREG decided to sell rather than keep the project, and o a $31.9 million after-tax write-down of the investment in Piney Orchard--a mixed-use, planned-unit development--which occurred because the expected future cash flow from the project was less than CREG's investment in the project. Power Projects Power projects held by our diversified businesses consist of the following: At December 31, 1998 1997 - ---------------------------------------------- (In millions) Domestic East $ 39.8 $ 41.3 West 426.2 377.7 International South America 21.6 18.3 Central America 161.8 5.2 Other 7.4 9.2 - ---------------------------------------------- Total power projects $656.8 $451.7 ============================================== Our Domestic-West power projects include investments of $310.6 million in 1998 and $261.4 million in 1997 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 1998, our power projects business recorded a $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. In 1996, our power projects business recorded a $14.6 million after-tax gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of a power purchase agreement. In addition, our power projects business had the following write-offs: o a $7.0 million after-tax write-off of an investment in two geothermal wholesale power generating projects that sell electricity under California power purchase agreements. These projects were written off because the expected future cash flow from the projects were less than the investments in the projects, o a $3.0 million after-tax write-off of development costs for a coal-fired power project when development efforts on the project were terminated, and o a $6.2 million after-tax write-off of a portion of an investment in a solar power project to reflect a settlement with the project's lender. Financial Investments Financial investments consist of the following: At December 31, 1998 1997 - ----------------------------------------------- (In millions) Insurance company $102.5 $ 88.8 Marketable equity securities 25.3 33.3 Financial limited partnerships 41.9 43.6 Leveraged leases 28.3 30.8 - ----------------------------------------------- Total financial investments $198.0 $196.5 =============================================== 55 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 diversified businesses' marketable equity securities 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, exclusive of $6.2 million in 1998 and $3.5 million in 1997 of unrealized net gains on securities of equity-method investees, in the following tables: Amortized Unrealized Unrealized Fair At December 31, 1998 Cost Basis Gains Losses Value - ------------------------------------------------------------------------ (In millions) Marketable Equity Securities $ 82.9 $24.2 $(0.4) $106.7 U.S. Government agency 12.7 0.4 -- 13.1 State municipal bonds 64.8 2.7 -- 67.5 - ------------------------------------------------------------------------ Totals $160.4 $27.3 $(0.4) $187.3 ======================================================================== Amortized Unrealized Unrealized Fair At December 31, 1997 Cost Basis Gains Losses Value - ------------------------------------------------------------------------ (In millions) Marketable Equity Securities $ 77.3 $12.0 $(0.5) $ 88.8 U.S. Government agency 14.9 0.2 -- 15.1 State municipal bonds 65.5 2.2 -- 67.7 - ------------------------------------------------------------------------ Totals $157.7 $14.4 $(0.5) $171.6 ======================================================================== These tables include $23.9 million in 1998 and $10.0 million in 1997 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: 1998 1997 1996 - ----------------------------------------------- (In millions) Gross realized gains $4.2 $ 9.3 $ 4.3 Gross realized losses (0.7) (0.6) (0.2) - ----------------------------------------------- Net realized gains $3.5 $ 8.7 $ 4.1 =============================================== The U.S. Government agency obligations and state municipal bonds mature on the following schedule: At December 31, 1998 Amount - -------------------------------------------------- (In millions) Less than 1 year $ -- 1-5 years 33.5 5-10 years 29.9 More than 10 years 17.2 - -------------------------------------------------- Total maturities of debt securities $ 80.6 ================================================== - -------------------------------------------------------------------------------- Note 4 Regulatory Assets (net) As discussed in Note 1, the Maryland PSC regulates our utility business. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under generally accepted accounting principles. 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 our regulatory assets and liabilities in the following table, and we discuss each of them separately on page 57. At December 31, 1998 1997 - ------------------------------------------------------------ (In millions) Income taxes recoverable through future rates (net) $252.6 $256.5 Deferred postretirement and postemployment benefit costs 90.0 96.4 Deferred nuclear expenditures 73.3 77.7 Deferred conservation expenditures 53.4 55.8 Deferred costs of decommissioning federal uranium enrichment facilities 38.5 42.4 Deferred environmental costs 33.4 38.8 Deferred fuel costs (net) 12.7 4.4 Deferred termination benefit costs 2.2 21.0 Other (net) 9.6 4.3 - ------------------------------------------------------------ Total regulatory assets (net) $565.7 $597.3 ============================================================ 56 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 utility business, but has not been reflected in the rates we charge our customers. These income taxes represent the tax effect of temporary differences in depreciation and the allowance for equity funds used during construction, offset by differences in deferred tax rates and deferred taxes on deferred investment tax credits. We amortize these amounts as the temporary differences reverse. Deferred Postretirement and Postemployment Benefit Costs Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for postretirement benefits) and SFAS 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 5. Deferred Nuclear Expenditures Deferred nuclear expenditures are the net unamortized balance of certain operations and maintenance costs at Calvert Cliffs. These expenditures consist of: o costs incurred from 1979 through 1982 for inspecting and repairing seismic pipe supports, o expenditures incurred from 1989 through 1994 associated with nonrecurring phases of certain nuclear operations projects, and o expenditures incurred during 1990 for investigating leaks in the pressurizer heater sleeves. We are amortizing these costs over the remaining life of the plant in accordance with the Maryland PSC's orders. Deferred Conservation Expenditures Deferred conservation expenditures include two components: o 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 o revenues we collected from customers in 1996 in excess of our profit limit under the conservation surcharge. The Maryland PSC allows us to collect from customers money spent on conservation programs under a "conservation surcharge." However, under this surcharge the Maryland PSC limits what our profit can be. If, at the end of the year, we have exceeded our allowed profit, we defer the excess in that year and we lower the amount of future surcharges to our customers to correct the amount of overage, plus interest. During 1996, we exceeded our profit limit under the conservation surcharge. As a result, we deferred $28.5 million of our 1996 revenue from surcharge billings as a regulatory liability. To correct the overage, we lowered the surcharge on our customers' bills over a 12-month period beginning July 1997 through June 1998. Deferred Costs of Decommissioning Federal Uranium Enrichment Facilities Deferred costs of decommissioning federal uranium enrichment facilities are the unamortized portion of our required contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. We are required, along with other domestic utilities, by the Energy Policy Act of 1992 to make contributions to the fund. 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 are amortizing these costs over the contribution period as a cost of fuel. We also discuss this in Note 1. 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) over a 10-year period in accordance with the Maryland PSC's November 1995 order. 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, 1998 1997 - --------------------------------------------------------- (In millions) Electric over-recovered fuel costs $(11.5) $(19.0) Gas deferred fuel costs 24.2 23.4 - --------------------------------------------------------- Deferred fuel costs (net) $ 12.7 $ 4.4 ========================================================= Deferred Termination Benefits Deferred termination benefit costs are the net unamortized balance of the cost of certain termination benefits offered to employees of our regulated utility operations in 1992 and 1993. We are amortizing these costs over a five-year period in accordance with the Maryland PSC's orders. 57 Note 5 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 largest plan covers nearly all BGE employees and certain employees of our subsidiaries. Our other plans, which are not material in amount, provide supplemental benefits to certain key employees. 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 retro- active 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, 1998 were mostly marketable equity and fixed income securities, and group annuity contracts. 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: o a transition obligation, which we are amortizing over 20 years, and o an increase in annual postretirement benefit costs. For our diversified businesses, we expense all postretirement benefit costs. For our utility business, we accounted for the increase in annual postretirement benefit costs under two Maryland PSC rate orders: o in an April 1993 rate order, the Maryland PSC allowed us to expense one-half and defer, as a regulatory asset (see Note 4), the other half of the increase in annual postretirement benefit costs related to our electric and gas businesses, and o in a November 1995 rate order, the Maryland PSC allowed us to expense all of the increase in annual postretirement benefit costs related to our gas business. Beginning in 1998, the Maryland PSC authorized us to: o expense all of the increase in annual postretirement benefit costs related to our electric business, and o amortize the regulatory asset for postretirement benefit costs related to our 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 table: Postretirement Pension Benefits Benefits 1998 1997 1998 1997 - ---------------------------------------------------------------------------- (In millions) Change in benefit obligation Benefit obligation at January 1, $ 902.0 $846.3 $320.3 $311.0 Service cost 21.6 16.8 6.6 5.4 Interest cost 63.0 61.3 23.4 21.8 Plan participants' contributions -- -- 2.0 2.0 Actuarial loss (gain) 102.9 35.5 48.9 (2.1) Benefits paid (58.2) (57.9) (18.1) (17.8) - ---------------------------------------------------------------------------- Benefit obligation at December 31, $1,031.3 $902.0 $383.1 $320.3 ============================================================================ Change in plan assets Fair value of plan assets at January 1, $912.3 $795.4 $ -- $ -- Actual return on plan assets 116.9 130.0 -- -- Employer contribution 14.5 44.8 16.1 15.8 Plan participants' contributions -- -- 2.0 2.0 Benefits paid (58.2) (57.9) (18.1) (17.8) - ---------------------------------------------------------------------------- Fair value of plan assets at December 31, $985.5 $912.3 $ -- $ -- ============================================================================ 58 Postretirement Pension Benefits Benefits 1998 1997 1998 1997 - -------------------------------------------------------------- (In millions) Funded status Funded status at December 31, $ (45.8) $ 10.3 $(383.1) $(320.3) Unrecognized net actuarial loss 137.6 84.2 59.7 10.9 Unrecognized prior service cost 16.9 19.4 -- -- Unrecognized transition obligation -- -- 159.3 170.6 Unamortized net asset from adoption of SFAS No. 87 (0.7) (0.9) -- -- - -------------------------------------------------------------- Prepaid (accrued) benefit cost $108.0 $113.0 $(164.1) $(138.8) ============================================================== Net Periodic Benefit Cost We show the components of net periodic pension benefit cost in the following table: Year Ended December 31, 1998 1997 1996 - ------------------------------------------------------------------ (In millions) Components of net periodic pension benefit cost Service cost $21.6 $16.8 $16.1 Interest cost 63.0 61.3 59.9 Expected return on plan assets (72.1) (66.9) (62.8) Amortization of transition asset (0.2) (0.2) (0.2) Amortization of prior service cost 2.5 2.5 2.5 Recognized net actuarial loss 5.6 4.6 4.9 Amount capitalized as construction cost (3.8) (2.5) (2.4) - ------------------------------------------------------------------ Net periodic pension benefit cost $16.6 $15.6 $18.0 ================================================================== We show the components of net periodic postretirement benefit cost in the following table: Year Ended December 31, 1998 1997 1996 - ----------------------------------------------------------------- (In millions) Components of net periodic postretirement benefit cost Service cost $ 6.6 $ 5.4 $ 5.5 Interest cost 23.4 21.8 21.9 Amortization of transition obligation 11.4 11.4 11.4 Recognized net actuarial loss 0.2 0.1 0.2 Amount capitalized as construction cost (8.1) (7.6) (6.2) Amount deferred -- (7.2) (7.4) - ----------------------------------------------------------------- Net periodic postretirement benefit cost $33.5 $23.9 $25.4 ================================================================= Assumptions We made the assumptions below to calculate our pension and postretirement benefit cost and obligations. Postretirement Pension Benefits Benefits At December 31, 1998 1997 1998 1997 - -------------------------------------------------------------- Discount rate 6.50% 7.25% 6.50% 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: o in 1998, 6.0% for both Medicare-eligible retirees and retirees not covered by Medicare, and o in 1999, 7.5% for Medicare-eligible retirees and 9.0% for retirees not covered by Medicare. After 1999, we assumed both inflation rates will decrease by 0.5% annually to a rate of 5.5% in the years 2003 and 2006. A 1% increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $52.8 million as of December 31, 1998 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $4.5 million annually. A 1% decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $41.7 million as of December 31, 1998 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $3.5 million annually. Other Postemployment Benefits We provide the following postemployment benefits: o 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 o income replacement payments for employees found to be disabled before November 1995. (Payments for employees found to be disabled after that date are paid by an insurance company, and the cost is paid by employees.) The liability for these benefits totaled $52.9 million as of December 31, 1998 and $45.4 million as of December 31, 1997. Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for Postemployment Benefits. We deferred, as a regulatory asset (see Note 4), the postemployment benefit liability attributable to our utility business as of December 31, 1993, consistent with the Maryland 59 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 current electric and gas base rates to recover the higher costs in 1998. We assumed the discount rate for other postemployment benefits to be 4.5% in 1998 and 6.0% in 1997. Employee Savings Plan Benefits We also sponsor a defined contribution savings plan that is offered to all eligible BGE employees 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: o $10.1 million in 1998, o $8.5 million in 1997, and o $9.4 million in 1996. - -------------------------------------------------------------------------------- Note 6 Short-Term Borrowings Summary of Short-Term Borrowings Our short-term borrowings may include bank loans, commercial paper notes, and bank lines of credit. Short-term borrowings mature within one year from the date of the financial statements. 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. As of December 31, 1998, we had no short-term borrowings outstanding. As of December 31, 1997, we had $316.1 million outstanding consisting entirely of BGE commercial paper notes. We had unused bank lines of credit supporting our commercial paper notes of $113 million at December 31, 1998 and $231 million at December 31, 1997. These amounts do not include unused revolving credit agreements of $100 million at December 31, 1998 and 1997 that are discussed in Note 7. Constellation Enterprises, Inc. has a $135 million unsecured revolving credit agreement that matures December 20, 1999, to provide liquidity for general corporate purposes including financing requirements of subsidiaries and to provide for the issuance of letters of credit to meet subsidiary business requirements. At December 31, 1998, letters of credit totaling $2.3 million were issued under this credit facility. Weighted-Average Interest Rates Our weighted-average effective interest rate for BGE's commercial paper notes was 5.65% for the year ended December 31, 1998 and 5.66% for 1997. - -------------------------------------------------------------------------------- Note 7 Long-Term Debt Long-term debt matures more than one year from the date of the financial statements. 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. We discuss BGE's and our diversified businesses' long-term debt separately below. BGE's Long-Term Debt BGE's First Refunding Mortgage Bonds BGE's first refunding mortgage bonds are secured by a mortgage lien on nearly all of its assets, including all utility properties and franchises and its subsidiary capital stock. BGE's subsidiary capital stock pledged under the mortgage is that of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc. BGE is required to make an annual sinking fund payment each August 1 to the mortgage trustee. The amount of the payment is equal to 1% of the highest principal amount of bonds outstanding during the preceding 12 months. The trustee uses these funds to retire bonds from any series through repurchases or calls for early redemption. However, the trustee cannot call the following bonds for early redemption: o 5 1/2% Installment Series, o 6 1/2% Series, due 2003 due 2002 o 6 1/8% Series, due 2003 o 8.40% Series, due 1999 o 5 1/2% Series, due 2004 o 5 1/2% Series, due 2000 o 7 1/2% Series, due 2007 o 8 3/8% Series, due 2001 o 6 5/8% Series, due 2008 o 7 1/4% Series, due 2002 60 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 We show the weighted-average interest rates and maturity dates for BGE's fixed-rate medium-term notes outstanding at December 31, 1998 in the following table: Weighted-Average Series Interest Rate Maturity Dates - ------------------------------------------------ B 8.10% 2000-2006 C 7.34 1999-2003 D 6.66 2001-2006 E 6.66 2006-2012 G 6.08 2008 Some of the medium-term notes include a "put option." These put options allow the holders to sell their notes back to BGE on the put option dates at a price equal to 100% of the principal amount. The following is a summary of medium-term notes with put options: Series E Notes Principal Put Option Dates - ------------------------------------------------------ (In millions) 6.75%, due 2012 $60.0 June 2002 and 2007 6.75%, due 2012 25.0 June 2004 and 2007 6.73%, due 2012 25.0 June 2004 and 2007 BGE has $100 million of revolving credit agreements with several banks that are available through 2000 to 2001. At December 31, 1998, BGE had no outstanding borrowings under these agreements. These banks charge us commitment fees based on the daily average of the unborrowed amount, and we pay market interest rates on any borrowings. These agreements also support BGE's commercial paper notes, as described in Note 6. Company 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 common securities and the preferred securities to purchase a series of 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038 (Debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the TOPrS. The Trust must redeem the TOPrS at $25 per preferred security plus accrued but unpaid distributions when the Debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the Debentures at any time on or after June 15, 2003 or at any time when certain tax or other events occur. The interest paid on the Debentures, which the Trust will use to make distributions on the TOPrS, is included in "Interest Expense" in the Consolidated Statements of Income and is deductible for income tax purposes. BGE fully and unconditionally guarantees the TOPrS based on its various obligations relating to the trust agreement, indentures, Debentures, and the preferred security guarantee agreement. The Debentures are the only assets of the Trust. The Trust is wholly owned by BGE because we own 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. Diversified Businesses' Long-Term Debt Revolving Credit Agreements A subsidiary of Constellation Enterprises, Inc. has a $75 million unsecured revolving credit agreement that matures December 9, 1999, to provide liquidity for general corporate purposes. Our diversified businesses pay a commitment fee based on the daily average of the unborrowed portion of the commitment. At December 31, 1998, our diversified businesses had $45.0 million outstanding under this agreement. Constellation Energy Source has a $10 million revolving credit agreement that matures February 1, 2000. At December 31, 1998, Constellation Energy Source had no outstanding borrowings under this agreement. Constellation Energy Source pays a facility fee based on the total amount of the commitment. 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. At December 31, 1998, ComfortLink had $29 million outstanding under this agreement. Mortgage and Construction Loans Our diversified businesses' mortgage and construction loans have varying terms. The following mortgage notes require monthly principal and interest payments: o 7.90%, due in 2000 o 7.357%, due in 2009 o 8.00%, due in 2001 o 9.65%, due in 2028 The 8.00% mortgage note due in 2003 requires interest payments until maturity. The variable rate mortgage notes and construction loans require periodic payment of principal and interest. The 8.00% mortgage note due in 2033, requires interest payments initially then monthly principal and interest payments. 61 Unsecured Notes The unsecured notes mature on the following schedule: Amount - ------------------------------------------------------ (In millions) 7.30%, due April 22, 1999 $ 90.0 8.73%, due October 15, 1999 15.0 7.125%, due March 13, 2000 15.0 7.55%, due April 22, 2000 35.0 7.50%, due May 5, 2000 139.0 7.43%, due September 9, 2000 30.0 5.43%, due October 15, 2000 5.0 7.66%, due May 5, 2001 135.0 5.67%, due May 5, 2001 152.0 - ------------------------------------------------------ Total unsecured notes at December 31, 1998 $616.0 ====================================================== Maturities of Long-Term Debt All of our long-term borrowings mature on the following schedule (includes sinking fund requirements): Diversified Year BGE Businesses - ------------------------------------------------------ (In millions) 1999 $ 334.5 $200.2 2000 252.6 273.4 2001 195.2 362.6 2002 154.0 1.5 2003 284.3 8.9 Thereafter 1,584.4 23.6 - ------------------------------------------------------ Total long-term debt at December 31, 1998 $2,805.0 $870.2 ====================================================== At December 31, 1998, BGE had long-term loans totaling $255.0 million that mature after 2002 (including $110 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, $145.0 million could potentially be repaid in 1999, $60.0 million in 2002, and $50.0 million thereafter. We have the ability and intent to refinance such debt by issuing medium-term notes or by borrowing under our revolving credit agreements, if necessary. Weighted-Average Interest Rates for Variable Rate Debt Our weighted-average interest rates for variable rate debt were: Year Ended December 31, 1998 1997 - -------------------------------------------------------------------------------- BGE Floating rate series mortgage bonds 5.90% 6.11% Remarketed floating rate series mortgage bonds 5.70 5.75 Medium-term notes, Series D 5.74 5.78 Pollution control loan 3.48 3.63 Port facilities loan 3.61 3.71 Adjustable rate pollution control loan 3.75 3.90 Economic development loan 3.59 3.69 Variable rate pollution control loan 3.45 3.73 Diversified Businesses Loans under credit agreement 6.02 6.04 Mortgage and construction loans 8.17 8.10 - -------------------------------------------------------------------------------- Note 8 Redeemable Preference Stock Priority For the payment of dividends and in the event of liquidation of BGE, preference stock is ranked prior to common stock. All preference stock are ranked equally. Redemptions in 1998 and 1999 During 1998, BGE redeemed all remaining shares of the following: o the 7.50%, 1986 series, o the 6.75%, 1987 series, and o the 8.625%, 1990 series. The redemptions were a combination of mandatory and optional sinking fund redemptions and early redemptions. The remaining 70,000 shares of the 7.85%, 1991 series will be redeemed on July 1, 1999 under mandatory sinking fund provisions. 62 Note 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. All other leases are operating leases and are reported in the Consolidated Statements of Income. We present information about our operating leases below. Incoming Lease Rentals Some of our diversified businesses, as landlords, lease retail space to others. These operating leases expire over periods ranging from one to 20 years, and have options to renew. At December 31, 1998, our diversified businesses had property under operating leases with a net book value of $32.4 million. At December 31, 1998, tenants owed our diversified businesses future minimum rentals under operating leases as follows: Year - -------------------------------------------------- (In millions) 1999 $ 3.4 2000 3.3 2001 3.1 2002 2.7 2003 2.7 Thereafter 24.3 - -------------------------------------------------- Total future minimum lease rentals $39.5 ================================================== 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: o $10.5 million in 1998, o $9.5 million in 1997, and o $11.6 million in 1996. At December 31, 1998, we owed future minimum payments for long-term, noncancelable, operating leases as follows: Year - ------------------------------------------------- (In millions) 1999 $ 6.7 2000 5.4 2001 4.1 2002 3.4 2003 2.2 Thereafter 5.5 - ------------------------------------------------- Total future minimum lease payments $27.3 ================================================= - -------------------------------------------------------------------------------- Note 10 Commitments, Guarantees, and Contingencies Commitments We have made substantial commitments in connection with our utility construction program for future years. In addition, our electric business has entered into 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: o $70.7 million in 1998, o $65.6 million in 1997, and o $64.1 million in 1996. At December 31, 1998, we estimate our future payments for capacity and energy that we are obligated to buy under these contracts to be: Year - ------------------------------------------------------------ (In millions) 1999 $ 61.9 2000 63.1 2001 33.4 2002 12.3 2003 12.3 Thereafter 128.3 - ------------------------------------------------------------ Total estimated future payments for capacity and energy under long-term contracts $311.3 ============================================================ Some of our diversified businesses have 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, 1998, the total amount of investment requirements committed to by our diversified businesses was $19.9 million. 63 In March 1998, our power marketing and trading business, Constellation Power Source, Inc. and Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., formed Orion Power Holdings, Inc. (Orion) to acquire electric generating plants in the United States and Canada. Constellation Power Source owns a minority interest in Orion, and BGE has committed to contribute up to $175 million in equity to Constellation Power Source to fund its investment in Orion. 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 a reserve for credit losses. At December 31, 1998, BGE had sold $33.6 million and BGE Home Products & Services had sold $45.3 million of receivables under these agreements. Guarantees 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, 1998, Safe Harbor Water Power Corporation had outstanding debt of $23.6 million, of which $15.7 million is guaranteed by BGE. BGE has issued guarantees in an amount up to $162 million related to credit facilities and contractual performance of certain of its diversified subsidiaries. At December 31, 1998, letters of credit totaling $2.3 million were issued under one of the credit facilities. At December 31, 1998, our diversified businesses had guaranteed outstanding loans and letters of credit of certain power projects and real estate projects totaling $59.7 million. Our diversified businesses also guarantee certain other borrowings of various power projects and real estate projects. We assess the risk of material loss from these guarantees to be minimal. Environmental Matters Clean Air The Clean Air Act of 1990 contains two titles designed to reduce emissions of sulfur dioxides and nitrogen oxides (NOx) from electric generating stations--Title IV and Title I. Title IV addresses emissions of sulfur dioxides. Compliance is required in two phases: o Phase I became effective January 1, 1995. We met the requirements of this phase by installing flue gas desulfurization system, switching fuels, and retiring some units. o Phase II must be implemented by January 1, 2000. We expect to meet the compliance requirements through some combination of switching fuels and allowance trading. Title I addresses emissions of NOx. The Maryland Department of the Environment (MDE) issued NOx regulations which took effect June 1, 1998. The MDE regulations require major NOx sources to reduce NOx emissions up to 65% by May, 1999. While we are already taking steps to control NOx emissions at our generating plants, we communicated to MDE that we could not install the required technology at our Brandon Shores plant in time to meet the MDE's May, 1999 deadline. On June 19, 1998, we filed a lawsuit against MDE in Baltimore challenging these regulations. On February 9, 1999, the Baltimore City Circuit Court ordered the MDE to reissue the regulations with a new compliance date, indicating it was impossible for utilities to meet the May, 1999 deadline. We do not anticipate that MDE will appeal the court's decision. The EPA issued a final rule in September, 1998 that requires the reduction of NOx emissions up to 85% by 22 states (including Maryland and Pennsylvania). The 22 states must submit plans to the EPA by September 1999 showing how they will meet its new requirements. Based on the MDE and EPA regulations, we currently estimate that the additional controls needed at our generating plants to meet the 65% NOx emission reduction requirements will cost approximately $126 million. Through December 31, 1998, we have spent approximately $21.5 million to meet the 65% reduction requirements. We cannot estimate the cost for the 85% reduction requirements at this time; however, these costs could be material. In July 1997, the EPA published National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. These standards may require increased controls at our fossil generating plants in the future. We cannot estimate the cost of these increased controls at this time because the states, including Maryland, still need to determine what reductions, if any, in pollutants will be necessary to meet the federal standards. 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 15.42% 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 $4.9 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. The cleanup costs for some of the remaining sites could be significant, but we do not expect them to have a material effect on our financial position or results of operations. 64 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 requires 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 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 4. Through December 31, 1998, we have spent approximately $32 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 costs, 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). 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 BGE. The primary contingencies that would result from an incident at Calvert Cliffs could include: o physical damage to the plant, o recoverability of replacement power costs, and o our liability to third parties for property damage and bodily injury. We have insurance policies that cover these contingencies, but the policies have certain 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 17 weeks, we have insurance coverage for replacement power costs up to $494.2 million per unit, provided by an industry mutual insurance company. This amount can be reduced by up to $98.8 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 $23.2 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 the date of this report, the limit for third party claims from a nuclear incident is $9.71 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. o BGE nuclear worker claims reported on or after January 1, 1998 are covered by a new insurance policy with an annual industry aggregate limit of $200 million for radiation injury claims against all those insured by this policy. o All nuclear worker claims reported prior to January 1, 1998 are still covered by the old 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 nine 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 above) would apply. Recoverability of Electric Fuel Costs By law, we are allowed to recover our cost of electric fuel as long as the Maryland PSC finds that, among other things, we have kept the productive capacity of our generating plants at a reasonable level. To do this, the Maryland PSC will perform an evaluation of each outage (other than regular maintenance outages) at our generating plants. The evaluation will determine if we used all reasonable and cost-effective maintenance and operating control procedures to try to prevent the outage. 65 The Maryland PSC, under the Generating Unit Performance Program, measures annually whether we have maintained the productive capacity of our generating plants at reasonable levels. To do this, the program uses a system-wide generating performance target and an individual performance target for each base load generating unit. In fuel rate hearings, actual generating performance adjusted for planned outages will be compared first to the system-wide target. If that target is met, it should mean that the requirements of Maryland law have been met. If the system-wide target is not met, each unit's adjusted actual generating performance will be compared to its individual performance target to determine if the requirements of Maryland law have been met and, if not, to determine the basis for possibly imposing a penalty on BGE. Even if we meet these targets, parties to fuel rate hearings may still question whether we used all reasonable and cost-effective procedures to try to prevent an outage. If the Maryland PSC decides we were deficient in some way, the Maryland PSC may not allow us to recover the cost of replacement energy. The two units at Calvert Cliffs use the cheapest fuel. As a result, the costs of replacement energy associated with outages at these units can be significant. We cannot estimate the amount of replacement energy costs that could be challenged or disallowed in future fuel rate proceedings, but such amounts could be material. During 1989 through 1991 we had extended outages at Calvert Cliffs. These outages drove up fuel costs, and resulted in fuel rate proceedings before the Maryland PSC for several years. In these proceedings, the Maryland PSC considered whether any portion of the extra fuel costs should be charged to BGE instead of passed on to customers. In December 1996, we settled the proceedings by agreeing not to bill our customers for $118 million of electric replacement energy costs associated with these outages. All costs associated with the outages in excess of $118 million have already been collected from customers through the fuel rate. In 1990, we wrote off $35 million of these costs. In 1996, we wrote off the remaining $83 million plus $5.6 million of related financing charges. The 1996 write-offs, together, reduced after-tax earnings by $57.6 million. Also in 1996, we wrote off $6.8 million of fuel costs related to earlier outages that were disallowed by the Maryland PSC. This write-off reduced 1996 after-tax earnings by $4.5 million. We have reported all of the 1996 write-offs as "Disallowed replacement energy costs" in our Consolidated Statements of Income. California Power Purchase Agreements Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc. (whose power projects are managed by Constellation Power) have $310.6 million invested in 15 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. In 1998, earnings from these projects were $41.3 million, or $.28 per share. Under these agreements, the projects supply electricity to utility companies at: o a fixed rate for capacity and energy for the first 10 years of the agreements, and o 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 transition period to describe the time frame when the 10-year periods for fixed energy rates expire for these 15 power generation projects and they begin supplying electricity at variable rates. The transition period for some of the projects began in 1996 and will continue for the remaining projects through 2000. At the date of this report, eight projects had already transitioned to variable rates and seven other projects will transition in 1999 and 2000. The projects that have already transitioned to variable rates have had lower revenues under variable rates than they did under fixed rates. However, we have not yet experienced total lower earnings from the California projects because the combined revenues from the remaining projects, which continue to supply electricity at fixed rates, are high enough to offset the lower revenues from the variable-rate projects. When the remaining projects transition to variable rates, we expect the revenues from those projects also to be lower than they are under fixed rates. Our power projects business is pursuing alternatives for some of these power generation projects including: o repowering the projects to reduce operating costs, o changing fuels to reduce operating costs, o renegotiating the power purchase agreements to improve the terms, o restructuring financings to improve the financing terms, and o selling its ownership interests in the projects. The California projects that make the highest revenues will transition to variable rates in 1999 and 2000. The projects which transition in 1999 contributed $10.7 million, or $.07 per share to 1998 earnings, while those changing over in 2000 contributed $24.0 million, or $.16 per share to 1998 earnings. We expect earnings to ultimately decrease by similar amounts beginning in 1999 as these projects transition. 66 Constellation Real Estate Most of Constellation Real Estate Group's (CREG) real estate 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. CREG's real estate projects have continued to incur carrying costs and depreciation over the years. Additionally, CREG 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 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 diversified 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 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 remaining 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. Management's current real estate strategy is to hold each real estate project until we can realize a reasonable value for it, except for Church Street Station which we intend to sell as discussed in Note 3. Management evaluates strategies for all its businesses, including real estate, on an ongoing basis. We anticipate that competing demands for our financial resources and changes in the utility industry will cause us to evaluate thoroughly all diversified business strategies on a regular basis so we use capital and other resources in a manner that is most beneficial. It may be helpful for you to understand when we are required, by accounting rules, to write down the value of a real estate project to market value. A write-down is required 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 future cash flow from the project is less than the investment in the project. We discuss our real estate projects and investments further in Note 3. Year 2000 Project We have not experienced any significant year 2000 problems to date and we do not expect any significant problems to impair our operations as we transition to the new century. However, due to the magnitude and complexity of the year 2000 issue, even the most conscientious efforts cannot guarantee that every problem will be found and corrected prior to January 1, 2000. We discuss our year 2000 project further in the "Year 2000 Readiness Disclosure" section of Management's Discussion and Analysis. - -------------------------------------------------------------------------------- Note 11 Fair Value of Financial Instruments The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts. We used the following methods and assumptions in estimating fair value disclosures for financial instruments. o Cash and cash equivalents, net accounts receivable, other current assets, certain current liabilities, short-term borrowings, current portions of long-term debt and preference stock and certain deferred credits and other liabilities: The amounts reported in the Consolidated Balance Sheets approximate fair value. o Investments and other assets where it was practicable to estimate fair value: The fair value is based on quoted market prices where available. o Fixed-rate long-term debt, and redeemable preference stock: The fair value is based on quoted market prices where available or by discounting remaining cash flows at current market rates. The carrying amount of variable-rate long-term debt approximates fair value. We show the carrying amounts and fair values of financial instruments included in our Consolidated Balance Sheets in the following table. At December 31, 1998 1997 - -------------------------------------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value - -------------------------------------------------------------------------- (In millions) Investments and other assets for which it is: Practicable to estimate fair value $ 213.0 $ 213.0 $ 197.4 $ 198.8 Not practicable to estimate fair value 56.5 N/A 57.5 N/A Fixed-rate long-term debt 2,954.7 3,076.6 2,637.5 2,718.4 Redeemable preference stock 7.0 7.2 113.0 116.5 67 It was not practicable to estimate the fair value of investments held by our diversified businesses in: o several financial partnerships that invest in nonpublic debt and equity securities, o several partnerships that own solar powered energy production facilities, and o a company involved in developing international power projects with a carrying amount of $3.7 million at December 31, 1998 and $3.0 million at December 31, 1997. 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 $41.9 million at December 31, 1998 and $43.6 million at December 31, 1997, representing ownership interests up to 10%. The total assets of all of these partnerships totaled $5.8 billion at December 31, 1997 (which is the latest information available). The investments in solar powered energy production facility partnerships totaled $10.9 million at December 31, 1998 and 1997, representing ownership interests up to 13%. The total assets of all of these partnerships totaled $41.5 million at December 31, 1997 (which is the latest information available). Guarantees It was not practicable to determine the fair value of certain loan guarantees of BGE and its diversified businesses. BGE guaranteed outstanding debt and other obligations totaling $18.0 million at December 31, 1998 and $20 million at December 31, 1997. Our diversified businesses guaranteed outstanding debt totaling $59.7 million at December 31, 1998 and $43 million at December 31, 1997. We do not anticipate that we will need to fund these guarantees. - -------------------------------------------------------------------------------- Note 12 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. 1998 QUARTERLY DATA
Earnings Earnings Income Applicable Per Share From Net to Common of Common Revenues Operations Income Stock Stock - ---------------------------------------------------------------------------------------- (In millions, except per share amounts) Quarter Ended: March 31 $ 866.1 $183.4 $ 80.2 $ 74.4 $0.50 June 30 767.6 156.2 63.2 57.4 0.39 September 30 934.0 320.4 167.7 160.9 1.08 December 31 790.4 81.1 16.6 13.2 0.09 - ---------------------------------------------------------------------------------------- Year Ended: December 31 $3,358.1 $741.1 $327.7 $305.9 $2.06 ======================================================================================== Our third quarter results include a $10.4 million after-tax gain for earnings in a partnership (see Note 3). Our fourth quarter results include: o a $15.4 million after-tax write-off of a real estate investment (see Note 3), and o a $5.5 million after-tax write-off of an energy services investment. (See the "Other Energy Services" section of Management's Discussion and Analysis.) 1997 Quarterly Data Earnings Earnings Income Applicable Per Share From Net to Common of Common Revenues Operations Income Stock Stock - ---------------------------------------------------------------------------------------- (In millions, except per share amounts) Quarter Ended: March 31 $ 887.7 $163.9 $ 72.1 $ 64.2 $0.43 June 30 746.4 78.8 15.0 7.1 0.05 September 30 860.8 321.0 171.4 164.4 1.11 December 31 812.7 159.9 24.3 18.4 0.12 - ---------------------------------------------------------------------------------------- Year Ended: December 31 $3,307.6 $723.6 $282.8 $254.1 $1.72 ========================================================================================
Our first quarter results include a $12.0 million after-tax write-down of a real estate project (see Note 3). Our second quarter results include a $31.9 million after-tax write-down of a real estate project (see Note 3). Our fourth quarter results include: o a $37.5 million after-tax write-off of merger costs (see Note 2), and o a $2.1 million after-tax write-down of a real estate project (see Note 3). THE SUM OF THE QUARTERLY EARNINGS PER SHARE AMOUNTS MAY NOT EQUAL THE TOTAL FOR THE YEAR DUE TO THE EFFECTS OF ROUNDING. 68 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item with respect to directors is set forth on pages 19 through 22 under "Election of BGE Directors" in the Proxy Statement and is incorporated herein by reference. The information required by this item with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in Item 4 of Part I of this Form 10-K under "Executive Officers of the Registrant," except that information with regard to a late filing of a Section 16(a) report by an executive officer is set forth on page 22 under "Section 16(a) Beneficial Ownership Reporting Compliance" in the Proxy Statement and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is set forth on pages 21 and 22 under "Directors' Compensation" on pages 24 through 28 under "Executive Compensation," and "Common Stock Performance Graph" and on pages 29 through 31 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 management is set forth on page 23 under "Security Ownership" in the Proxy Statement and is incorporated herein by reference. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS NAME OF TITLE AMOUNT OF PERCENT BENEFICIAL OF BENEFICIAL OF OWNER CLASS OWNERSHIP CLASS - ------------------------ -------- ------------------- -------- Capital Research and Common 10,225,000 shares 6.9% Management Company Stock 333 South Hope Street Los Angeles, CA 90071 ............ ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item is set forth on page 22 under "Certain Relationships and Transactions" in the Proxy Statement and is incorporated herein by reference. 69 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 15, 1999 of PricewaterhouseCoopers LLP Consolidated Statements of Income for three years ended December 31, 1998 Consolidated Statements of Comprehensive Income for three years ended December 31, 1998 Consolidated Balance Sheets at December 31, 1998 and December 31, 1997 Consolidated Statements of Cash Flows for three years ended December 31, 1998 Consolidated Statements of Common Shareholders' Equity for three years ended December 31, 1998 Consolidated Statements of Capitalization at December 31, 1998 and December 31, 1997 Consolidated Statements of Income Taxes for three years ended December 31, 1998 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. 70 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.) *3(a) -- 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(b) -- By-Laws 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) -- 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) *October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a) *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) *July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b) *October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4 *March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a) *June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(b) -- 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(c) -- 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(d) -- 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(e) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(f) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(g) -- 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). *10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q dated November 14, 1996, File No. 1-1910.) *10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.) *10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) *10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred Compensation Plan, as amended and restated. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31, 1996, File No. 1-1910.) 71 *10(e) -- Amended and Restated Baltimore and Gas and Electric Company Deferred Compensation Plan for Non-Employee Directors. (Designated as Exhibit No. 10 in Form 10-Q dated November 13, 1997, File No. 1-1910.) *10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) (Terminated effective August 1, 1997.) 10(g) -- Summary of severance arrangement for a named executive officer. *10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) *10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.) *10(j) -- Severance Agreements between Baltimore Gas and Electric Company and eight key employees. (Designated as Exhibit No. 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-1910.) 10(k) -- Form of amendment to Severance Agreements between Baltimore Gas and Electric Company and eight key employees. 10(l) -- Constellation Enterprises, Inc. Deferred Compensation Plan for Non-Employee Directors. 10(m) -- Summary of enhanced retirement benefits for a named executive officer. *10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore Gas and Electric Company and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 13, 1996, File No. 1-1910.) 12 -- 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. 27 -- Financial Data Schedule. *99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.) - ---------- * Incorporated by Reference. (b) Reports on Form 8-K: None. 72 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 AT TO COSTS CHARGED 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: Accumulated Provision for Uncollectibles 1998 ................................... $ 24.1 $ 28.0 $ -- $( 31.8)(A) $ 20.3 1997 ................................... 18.0 34.4 -- ( 28.3)(A) 24.1 1996 ................................... 16.4 24.9 -- ( 23.3)(A) 18.0 Valuation Allowance -- Net unrealized (gain) loss on available for sale securities 1998 ................................... ( 7.6) -- ( 1.8)(B) -- ( 9.4) 1997 ................................... ( 8.8) -- 1.2(B) -- ( 7.6) 1996 ................................... ( 6.2) -- ( 2.6)(B) -- ( 8.8) Valuation Allowance -- Net unrealized (gain) loss on nuclear decommissioning trust fund 1998 ................................... (10.0) -- (13.9)(C) -- (23.9) 1997 ................................... ( 3.7) -- ( 6.3)(C) -- (10.0) 1996 ................................... ( 2.2) -- ( 1.5)(C) -- ( 3.7) Provision for possible disallowance of replacement energy costs 1998 ................................... -- -- -- -- -- 1997 ................................... 118.0 -- -- (118.0)(D) -- 1996 ................................... 35.0 83.0 -- -- 118.0 Energy projects under development reserves 1998 ................................... -- -- -- -- -- 1997 ................................... 5.2 0.3 -- ( 5.5)(E) -- 1996 ................................... 0.3 5.2 -- ( 0.3)(E) 5.2
- ---------- (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 credited to accumulated depreciation. (D) Represents removal of a reserve based on actual disallowance of replacement energy costs. (E) Represents removal of a reserve associated with an energy project of a subsidiary that was abandoned. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 73 SIGNATURES 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 18, 1999 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 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/ C. H. POINDEXTER Chairman of the Board, President, March 18, 1999 ----------------------------------- Chief Executive Officer, and C. H. POINDEXTER Director Principal financial and accounting officer: By /s/ D. A. BRUNE Vice President, Chief Financial March 18, 1999 ----------------------------------- Officer and Secretary D. A. BRUNE Directors: /s/ H. F. BALDWIN Director March 18, 1999 - ------------------------------------- H. F. BALDWIN /s/ D. L. BECKER Director March 18, 1999 - ------------------------------------- D. L. BECKER /s/ B. B. BYRON Director March 18, 1999 - ------------------------------------- B. B. BYRON /s/ J. O. COLE Director March 18, 1999 - ------------------------------------- J. O. COLE /s/ D. A. COLUSSY Director March 18, 1999 - ------------------------------------- D. A. COLUSSY /s/ E. A. CROOKE Director March 18, 1999 - ------------------------------------- E. A. CROOKE /s/ J. R. CURTISS Director March 18, 1999 - ------------------------------------- J. R. CURTISS /s/ J. W. GECKLE Director March 18, 1999 - ------------------------------------- J. W. GECKLE /s/ F. A. HRABOWSKI III Director March 18, 1999 - ------------------------------------- F. A. HRABOWSKI III /s/ N. LAMPTON Director March 18, 1999 - ------------------------------------- N. LAMPTON /s/ C. R. LARSON Director March 18, 1999 - ------------------------------------- C. R. LARSON
74
SIGNATURE TITLE DATE --------- ----- ---- /s/ G. V. MCGOWAN Director March 18, 1999 - ------------------------------------- G. V. MCGOWAN /s/ G. L. RUSSELL, JR. Director March 18, 1999 - ------------------------------------- G. L. RUSSELL, JR. /s/ M. D. SULLIVAN Director March 18, 1999 - ------------------------------------- M. D. SULLIVAN
75 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.) *3(a) -- 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(b) -- By-Laws 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) -- 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) *October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a) *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) *July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b) *October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4 *March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a) *June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(b) -- 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(c) -- 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(d) -- 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(e) -- Form of Preferred Securities Guarantee (Designated as Exhibit 4(f) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(f) -- Form of Junior Subordinated Debenture (Designated as Exhibit 4(h) in Form S-3 dated May 28, 1998, File No. 333-53767). *4(g) -- 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). *10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q dated November 14, 1996, File No. 1-1910.) *10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.) *10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) 76 *10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred Compensation Plan, as amended and restated. (Designated as Exhibit No. 10(d) to the Annual Report on Form 10-K for the year ended December 31, 1996, File No. 1-1910.) *10(e) -- Amended and Restated Baltimore and Gas and Electric Company Deferred Compensation Plan for Non-Employee Directors. (Designated as Exhibit No. 10 in Form 10-Q dated November 13, 1997, File No. 1-1910.) *10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) (Terminated effective August 1, 1997.) 10(g) -- Summary of severance arrangement for a named executive officer. *10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) *10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.) *10(j) -- Severance Agreements between Baltimore Gas and Electric Company and eight key employees. (Designated as Exhibit No. 10(k) to the Annual Report on Form 10-K for the year ended December 31, 1997, File No. 1-1910.) 10(k) -- Form of amendment to Severance Agreements between Baltimore Gas and Electric Company and eight key employees. 10(l) -- Constellation Enterprises, Inc. Deferred Compensation Plan for Non-Employee Directors. 10(m) -- Summary of enhanced retirement benefits for a named executive officer. *10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore Gas and Electric Company and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 13, 1996, File No. 1-1910.) 12 -- 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. 27 -- Financial Data Schedule. *99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.) - ---------- * Incorporated by Reference. 77 EX-10 2 EXHIBIT 10(G) Exhibit 10(g) Summary Severance Arrangement For A Named Executive Officer In connection with Bruce M. Ambler's early retirement, and in recognition of his service as President and Chief Executive Officer of Constellation Holdings, Inc., he received a severance package when he retired on January 1, 1999. His severance benefits include a $509,503 lump sum severance payment equal to the total of (1) annual base salary, (2) average of the two highest annual bonus percentages earned during the preceding five years multiplied by the prior year's final annual salary, (3) payment toward the cost of active employee health coverage for 12 months, and (4) vacation accrual. He also receives a pension benefit computed at 60% of total final average salary plus bonus, and retired executive life insurance, home security, planning, and club membership benefits. His effective cost of medical and dental benefits beginning January 1, 2000 will be the same as if he were retired at age 60 with 20 years of service. Mr. Ambler received a 1998 short-term incentive payment, and will be entitled to a prorata payout of any earned performance-based restricted stock award for the 1997-1999 and 1998-2000 performance periods. EX-10 3 EXHIBIT 10(K) Exhibit 10(k) FORM OF AMENDMENT TO SEVERANCE AGREEMENTS BETWEEN BALTIMORE GAS AND ELECTRIC COMPANY AND EIGHT KEY EMPLOYEES AMENDMENT authorized by the Board of Directors of Baltimore Gas and Electric Company (the "Board"), to the Severance Agreement made the [ ] day of [ ], by and between Baltimore Gas and Electric Company (the "Company") and [EMPLOYEE NAME]("Agreement"). W I T N E S S E T H: WHEREAS, Section 8 of the Agreement gives the Board the authority to make certain amendments to the Agreement. WHEREAS, the Agreement is being amended to modify the benefits provided thereunder. NOW, THEREFORE, the Agreement is amended effective January 15, 1999 by the Board as authorized at its January 15, 1999 meeting as follows: 1. Section 2(a) is deleted and replaced with the following: "(a) Severance Payment. The Company shall pay to the Executive an amount equal to two times the Executive's annual base salary (as in effect on the date of the Qualifying Termination, not reduced by any reduction described in Section 1.6(b) above) and Annual Award Amount. The payment shall be made in twenty-four equal monthly installments beginning on the first day of the month following the Qualifying Termination." 2. Section 2(b) is deleted and replaced with the following: "(b) Supplemental Retirement Benefits. For purposes of determining the Executive's supplemental retirement benefits which the Executive is entitled to under the Company's Executive Benefits Plan (or the supplemental retirement plan maintained by a successor company), (i) the Executive's age shall be deemed equal to the greater of (A) age 55 or (B) the Executive's actual age, (ii) the Executive's service shall be deemed equal to the greater of (A) 10 or (B) the Executive's actual service plus 3, and (iii) any minimum service eligibility requirements for such benefits shall be waived." 3. Section 2(c) is renamed Section 2(d). 4. New Section 2(c) is added as follows: "(d) Severance Health Benefits. The Company shall provide to the Executive and the Executive's family medical and dental benefits on the same basis and on the same terms as any retiree who has attained the deemed age and service used to compute supplemental retirement benefits in Section 2(b) above." 5. Section 3(b) is deleted and replaced with the following: "(b) Supplemental Retirement Benefits. For purposes of determining the Executive's supplemental retirement benefits which the Executive is entitled to under the Company's Executive Benefits Plan (or the supplemental retirement plan maintained by a successor company), (i) the Executive's service shall be deemed equal to the greater of (A) 10 or (B) the Executive's actual service, and (ii) the Early Retirement Adjustment Factor (as such term is defined in the Company's Pension Plan or within the meaning of the tax qualified retirement plan maintained by a successor company) will be one (1)." Amendment Acknowledged: Baltimore Gas and Electric Company By: _____________________________ ---------------------------------- [EMPLOYEE NAME] EX-10 4 EXHIBIT 10(L) Exhibit 10(l) CONSTELLATION ENTERPRISES, INC. DEFERRED COMPENSATION PLAN FOR NON-EMPLOYEE DIRECTORS 1. Objective. The objective of this Plan is to provide a portion of the Compensation of non-employee Directors of CEI in the form of Stock Units, thereby promoting a greater identity of interest between CEI's non-employee Directors and its parent company's stockholders, and to enable such Directors to defer receipt of the portion of their Compensation that is payable in cash. 2. Definitions. As used herein, the following terms will have the meaning specified below: "Annual Retainer" means the amount payable by CEI to a Director as annual compensation for performance of services as a Director, and includes Committee Chair retainers. All other amounts (including without limitation Board/committee meeting fees, and expense reimbursements) shall be excluded in calculating the amount of the Annual Retainer. "BGE" means Baltimore Gas and Electric Company, a Maryland corporation, or its successor. "Board" means the Board of Directors of CEI. "Cash Account" means an account by that name established pursuant to Section 7. The maintenance of Cash Accounts is for bookkeeping purposes only. "Change in Control" 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 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 BGE or the combined voting power of BGE's then outstanding shares of voting securities entitled to a vote generally, or (ii) the approval by the stockholders of BGE of a reorganization, merger or consolidation, in each case, with respect to which persons who were stockholders of BGE 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 BGE or the sale of substantially all of its assets, or (iv) a change of more than one-half of the members of the board of directors of BGE within a 90-day period for reasons other than the death, disability, or retirement of such members, or (v) the purchase or acquisition by any person, entity or group of persons (within the meaning of section 13(d) or 14(d) of 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 CEI or the combined voting power of CEI's then outstanding shares of voting securities entitled to a vote generally unless such purchase or acquisition is deemed to have occurred as the result of a reorganization, merger or consolidation involving BGE, or (vi) the approval by the stockholders of CEI of a reorganization, merger or consolidation, in each case, with respect to which persons who were stockholders of CEI 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 (vii) a liquidation or dissolution of CEI or the sale of substantially all of its assets, or (viii) a change of more than one-half of the members of the Board of Directors of CEI within a 90-day period for reasons other than the death, disability, or retirement of such members. "CEI" means Constellation Enterprises, Inc., a Maryland corporation, or its successor. "Common Stock" means the common stock, without par value, of BGE. "Compensation" means any Annual Retainer and meeting fees payable by CEI to a participant in his/her capacity as a Director. Compensation excludes expense reimbursements paid by CEI to a participant in his/her capacity as a Director. "Deferred Cash Compensation" means any cash Compensation that is voluntarily deferred by a participant pursuant to Section 6. "Director" means a member of the Board who is not an employee of CEI or any of its subsidiaries/affiliates. "Disability" or "Disabled" means that the Plan Administrator has determined that the participant is unable to fulfill his/her responsibilities of Board membership because of illness or injury. For purposes of this Plan, a participant's eligibility to participate shall be deemed to have terminated 2 on the date he/she is determined by the Plan Administrator to be Disabled. "Earnings" means, with respect to the Cash Account, hypothetical interest credited to the Cash Account. "Earnings" means, with respect to the Stock Account, hypothetical dividends credited to the Stock Account. "Fair Market Value" means, as of any specified date, the average closing price of a share of Common Stock, reported in "New York Stock Exchange Composite Transactions" as published in the Eastern Edition of The Wall Street Journal for the most recent 30 days during which Common Stock was traded on the New York Stock Exchange (including such valuation date if a trading date). "Plan Accounts" means a participant's Cash Account and/or Stock Account. The maintenance of Plan Accounts is for bookkeeping purposes only. "Plan Administrator" means, as set forth in Section 3, the Board. "Stock Account" means an account by that name established pursuant to Section 8. The maintenance of Stock Accounts is for bookkeeping purposes only. "Stock Unit(s)" means the share equivalents credited to a Participant's Stock Account pursuant to Section 8. The use of Stock Units is for bookkeeping purposes only; the Stock Units are not actual shares of Common Stock. CEI will not reserve or otherwise set aside any Common Stock for or to any Stock Account. 3. Plan Administration. (i) Plan Administrator - The Plan is administered by the Board, who has sole authority to interpret the Plan, and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective. Decisions by the Plan Administrator shall be final and binding upon all persons for all purposes. The Plan Administrator shall have the power to delegate all or any part of its non-discretionary duties to one or more designees, and to withdraw such authority, by written designation. (ii) Amendment - This Plan may be amended from time to time or suspended or terminated at any time, at the written direction of the Plan Administrator. However, amendments required to keep the Plan in compliance with applicable laws and 3 regulations may be made by the Secretary of CEI (or other officer of CEI succeeding to that function) on advice of counsel. Nothing herein creates a vested right. (iii) Indemnification - The Plan Administrator (and its designees), Chairman of the Board, Chief Executive Officer, President, and Secretary of CEI and all other employees of CEI or its subsidiaries/affiliates whose assigned duties include matters under the Plan, shall be indemnified by CEI or its subsidiaries/affiliates or from proceeds under insurance policies purchased by CEI or its subsidiaries/affiliates, against any and all liabilities arising by reason of any act or failure to act made in good faith pursuant to the provisions of the Plan, including expenses reasonably incurred in the defense of any related claim. 4. Eligibility and Participation. (i) Mandatory participation - A Director is required to participate in this Plan with respect to the receipt of fifty percent (50%) of his/her Annual Retainer in the form of Stock Units under Section 5 of the Plan, while so classified. (ii) Voluntary participation - A Director is eligible to participate in the Plan by electing to defer the remainder of the participant's Compensation, that is payable in cash, under Section 6 of the Plan, while so classified. (iii) Termination of participation - Eligibility to participate shall terminate on the date the participant ceases to be a Director. Notwithstanding termination of eligibility, such person with Plan Accounts will remain a participant of the Plan, solely for purposes of the administration of existing Plan Accounts, and no additional Stock Units will be granted and no further deferrals of cash Compensation under the Plan will be permitted. 5. Mandatory Stock Units. The Stock Account of a participant will be credited on January 1 of each calendar year with Stock Units equal to the number of shares of Common Stock (including fractions of a share) that could have been purchased, with fifty percent (50%) of the participant's Annual Retainer for such calendar year, at Fair Market Value on such January 1. If a participant initially becomes eligible to participate in the Plan during a calendar year, the Stock Account of the participant for such calendar year will be credited, on the date that is the first day of the calendar month after the 4 participant initially becomes eligible to participate in the Plan, with Stock Units equal to the number of shares of Common Stock (including fractions of a share) that could have been purchased at Fair Market Value on such date, with an amount equal to (i) fifty percent (50%) of the participant's Annual Retainer multiplied by (ii) a fraction the numerator of which is the number of full calendar months in the calendar year on and after such date, and the denominator of which is 12. The Stock Account will be maintained pursuant to Section 8. 6. Cash Compensation Deferral Election. A participant may elect to defer all of his/her Annual Retainer that is payable in cash (i.e., fifty percent (50%) of the Annual Retainer) and/or may elect to defer all of his/her other Compensation that is payable in cash (i.e., one hundred percent (100%) of all other Compensation). A participant's cash Compensation deferral election with respect to the Annual Retainer shall specify whether the deferred Annual Retainer is to be credited to the Cash Account or to the Stock Account. All other Cash Compensation that a participant elects to defer will be credited to the Cash Account. Such election shall be made by written notification to the Secretary of CEI (or other officer of CEI succeeding to that function). Such election shall be made prior to the calendar year during which the applicable cash Compensation is payable, and shall be effective as of the first day of such calendar year. If a participant initially becomes eligible to participate in the Plan during a calendar year, the election for such calendar year must be made within thirty (30) calendar days after the date the participant initially becomes eligible to participate in the Plan, and shall be effective with respect to Compensation earned after the date the election is received by the Secretary of CEI (or other officer of CEI succeeding to that function). Elections under this Section shall remain in effect for all succeeding calendar years until revoked. Elections may be revoked by written notification to the Secretary of CEI (or other officer of CEI succeeding to that function), and shall be effective as of the first day of the calendar year following the calendar year during which the revocation is received by the Secretary of CEI. Notwithstanding anything herein contained to the contrary, the Plan Administrator shall have the right in its sole discretion to permit a participant to defer a portion (rather than all) of his/her Annual Retainer and/or other Compensation that is payable in cash. 5 7. Cash Accounts. Cash Compensation that consists of the Annual Retainer that a participant has elected to defer into the Cash Account is credited to the participant's Cash Account on January 1 (or if later, the date the participant's initial election to participate in the Plan becomes effective). All other cash Compensation that a participant has elected to defer is credited to the participant's Cash Account on each date such cash Compensation would otherwise have been paid to the Director. A participant's Cash Account shall be credited with earnings at the rate earned by the Interest Income Fund under the Baltimore Gas and Electric Company Employee Savings Plan, and computed in the same manner as under such plan. Earnings are credited to the Cash Account commencing on the date the applicable Deferred Cash Compensation is credited to the Cash Account. 8. Stock Accounts. Cash Compensation that consists of the Annual Retainer that a participant has elected to defer into the Stock Account is credited to the participant's Stock Account on January 1 (or if later, the date the participant's initial election to participate in the Plan becomes effective). A participant's Stock Account shall be credited with Stock Units equal to the number of shares of Common Stock (including fractions of a share) that could have been purchased with such Deferred Cash Compensation, at Fair Market Value on such date. Grants of mandatory Stock Units are credited to the Stock Account as set forth in Section 5. As of any dividend distribution date for the Common Stock, the participant's Stock Account shall be credited with additional Stock Units equal to the number of shares of Common Stock (including fractions of a share) that could have been purchased, at the closing price of a share of Common Stock on such date as reported in "New York Stock Exchange Composite Transactions" as published in the Eastern Edition of the The Wall Street Journal, with the amount which would have been paid as dividends on that number of shares (including fractions of a share) of Common Stock which is equal to the number of Stock Units then credited to the participant's Stock Account. In the event of any change in the outstanding shares of Common Stock by reason of any stock dividend or split, recapitalization, combination or exchange of shares or other similar changes in the Common Stock, then appropriate adjustments shall be made in the number of Stock Units in each participant's Stock Account. Such adjustments shall be made effective on the date of the change related to the Common Stock. 6 9. Distributions of Plan Accounts. Distributions of Plan Accounts shall be made in cash only, from the general assets of CEI. A participant may elect (by notification in the form and manner established by the Secretary of CEI (or other officer of CEI succeeding to that function) from time to time) to begin distributions (i) in the calendar year following the calendar year that eligibility to participate terminates, (ii) in the calendar year following the calendar year in which a participant attains age 70, if later, or (iii) any calendar year between (i) and (ii). Such election must be made prior to the end of the calendar year in which eligibility to participate terminates. Alternatively, a participant who reaches age 70 while still eligible to participate may elect to begin distributions, in the calendar year following the calendar year that the participant reaches age 70, of amounts in his/her Plan Accounts as of the end of the calendar year the participant reaches age 70. Such election must be made prior to the end of the calendar year in which the participant reaches age 70, and a distribution election to receive any subsequently deferred amounts beginning in the calendar year following the calendar year that eligibility to participate terminates, must be made prior to the end of the calendar year in which eligibility to participate terminates. A participant may elect (by notification in the form and manner established by the Secretary of CEI (or other officer of CEI succeeding to that function) from time to time) to receive distributions in a single payment or in annual installments during a period not to exceed fifteen years. The single payment or the first installment payment, whichever is applicable, shall be made within the first sixty (60) calendar days of the calendar year elected for distribution. Subsequent installments, if any, shall be made within the first sixty (60) calendar days of each succeeding calendar year until the participant's Cash Account has been paid out. In the event applicable elections are not timely made, a participant shall receive a distribution in a single payment within the first sixty (60) calendar days of the calendar year following the calendar year that eligibility to participate terminates. The value of the Stock Account, which is equal to the number of Stock Units in the Stock Account multiplied by the Fair Market Value on the date on which the participant's eligibility to participate terminates (or, the date that is 7 the last day of the calendar year during which the participant reaches age 70, for a participant who elects to begin distributions while still eligible to participate), is transferred to the Cash Account on such date. Earnings are credited to the Cash Account through the date of distribution, and amounts held for installment payments shall continue to be credited with Earnings. The value of the Cash Account that is payable in cash on the date of the single payment distribution is equal to the balance in the Cash Account on the date that is no earlier than five (5) calendar days prior to the day of such distribution ("Distribution Valuation Date"). The amount of any cash distribution to be made in installments from the Cash Account will be determined by multiplying (i) the balance in such Cash Account on the Distribution Valuation Date by (ii) a fraction, the numerator of which is one and the denominator of which is the number of installments in which distributions remain to be made (including the current distribution). If a participant dies or becomes Disabled, the entire unpaid balance of his/her Plan Accounts shall be paid to the beneficiary(ies) designated by the participant by notification in the form and manner established by the Secretary of CEI (or other officer of CEI succeeding to that function) from time to time or, if no designation was made, in the event of death, to the estate of the participant, and in the event of Disability, to the participant. Payment shall be made within sixty (60) calendar days after notice of death or Disability is received by the Secretary, unless prior to the participant's death or Disability, the participant elected (in the form and manner established by the Secretary of CEI (or other officer of CEI succeeding to that function) from time to time) a delayed and/or installment distribution option for such beneficiary(ies); provided, however that (i) such a distribution option election shall be effective only if the value of the participant's Plan Accounts is more than $50,000 on the date of the participant's death or Disability; and (ii) the final distribution must be made to such beneficiary(ies) no later than 15 years after the participant's death or Disability. After the end of the calendar year that a participant's eligibility to participate terminates, a distribution option election for a particular beneficiary is irrevocable; provided, however, that the participant may make a distribution option election for a new beneficiary who is initially designated after the participant's eligibility to participate terminates, and such election is irrevocable with respect to the new beneficiary. 8 The value of the Stock Account, which is equal to the number of Stock Units in the Stock Account multiplied by the Fair Market Value on the date of the participant's death or Disability, is transferred to the Cash Account on such date. Earnings are credited to the Cash Account through the date of distribution, and amounts held for installment payments shall continue to be credited with Earnings. The value of the Cash Account that is payable in cash on the date of the single payment distribution is equal to the balance in the Cash Account on the date that is no earlier than five (5) calendar days prior to the day of such distribution ("Beneficiary Distribution Valuation Date"). The amount of any cash distribution to be made in installments from the Cash Account will be determined by multiplying (i) the balance in such Cash Account on the Beneficiary Distribution Valuation Date by (ii) a fraction, the numerator of which is one and the denominator of which is the number of installments in which distributions remain to be made (including the current distribution). Upon the death of a participant's beneficiary for whom a delayed and/or installment distribution option was elected, the entire unpaid balance of the participant's Cash Account shall be paid to the beneficiary(ies) designated by the participant's beneficiary by notification in the form and manner established by the Secretary of CEI (or other officer of CEI succeeding to that function) from time to time or, if no designation was made, to the estate of the participant's beneficiary. Payment shall be made within sixty (60) calendar days after notice of death is received by the Secretary . The value of the Cash Account that is payable in cash is equal to the balance in the Cash Account on the date that is no earlier than five (5) calendar days prior to the day of such distribution. Notwithstanding anything herein contained to the contrary, the Plan Administrator shall have the right in its sole discretion to (i) vary the manner and timing of distributions of a participant or beneficiary entitled to a distribution under this Section 9, and may make such distributions in a single payment or over a shorter or longer period of time than that elected by a participant; and (ii) vary the period during which the closing price of Common Stock is referenced to determine the value of the Stock Account that is transferred to the Cash Account on the date on which the participant's eligibility to participate terminates. Any affected participants will not participate in exercising such discretion. 9 10. Beneficiaries. A participant shall have the right to designate, change or rescind a beneficiary(ies) who is to receive a distribution(s) pursuant to Section 9 in the event of the death or Disability of the participant. A participant's beneficiary(ies) for whom a delayed and/or installment distribution option was elected shall have the right to designate a beneficiary(ies) who is to receive a distribution pursuant to Section 9 in the event of the death of the participant's beneficiary(ies). Any designation, change or recision of the designation of beneficiary shall be made by notification in the form and manner established by the Secretary of CEI (or other officer of CEI succeeding to that function) from time to time. The last designation of beneficiary received by the Secretary shall be controlling over any testamentary or purported disposition by the participant (or, if applicable, the participant's beneficiary(ies)), provided that no designation, recision or change thereof shall be effective unless received by the Secretary prior to the death or Disability (whichever is applicable) of the participant (or, if applicable, the death of the participant's beneficiary(ies)). If the designated beneficiary is the estate, or the executor or administrator of the estate, of the participant (or, if applicable, the participant's beneficiary(ies)), a distribution pursuant to Section 9 may be made to the person(s) or entity (including a trust) entitled thereto under the will of the participant (or, if applicable, the participant's beneficiary(ies)), or, in the case of intestacy, under the laws relating to intestacy. 11. Valuation of Plan Accounts. The Plan Administrator shall cause the value of a participant's Plan Accounts to be determined and reported to CEI and the participant at least once per year as of the last business day of the calendar year. The value of the Stock Account will equal the number of Stock Units in the Stock Account multiplied by the closing price of a share of Common Stock on the last business day of the calendar year as reported in "New York Stock Exchange Composite Transactions" as published in the Eastern Edition of the The Wall Street Journal. The value of the Cash Account will equal the balance in the Cash Account on the last business day of the calendar year. 12. Withdrawals. No withdrawals of Plan Accounts may be made, except a participant may at any time request a hardship withdrawal from his/her Plan Accounts if he/she has incurred an unforeseeable financial emergency. An unforeseeable 10 financial emergency is defined as severe financial hardship to the participant resulting from a sudden and unexpected illness or accident of the participant (or of his/her dependents), loss of the participant's property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant. The need to send a child to college or the desire to purchase a home are not considered to be unforeseeable emergencies. The circumstance that will constitute an unforeseeable emergency will depend upon the facts of each case. A hardship withdrawal will be permitted by the Plan Administrator only as necessary to satisfy an immediate and heavy financial need. A hardship withdrawal may be permitted only to the extent reasonably necessary to satisfy the financial need. Payment may not be made to the extent that such hardship is or may be relieved (i) through reimbursement or compensation by insurance or otherwise, (ii) by liquidation of the participant's assets, to the extent the liquidation of such assets would not itself cause severe financial hardship, or (iii) by cessation of deferrals under the Plan. The request for hardship withdrawal shall be made by notification in the form and manner established by the Plan Administrator from time to time. Such hardship withdrawal will be permitted only with approval of the Plan Administrator. The participant will receive a lump sum payment after the Plan Administrator has had reasonable time to consider and then approve the request. The value of the Stock Account for purposes of processing a hardship cash withdrawal is equal to the number of Stock Units in the Stock Account multiplied by the Fair Market Value on the date on which the hardship withdrawal is processed. The value of the Cash Account for purposes of processing a hardship cash withdrawal is equal to the balance in the Cash Account on the date on which the hardship withdrawal is processed. 13. Change in Control. The terms of this Section 13 shall immediately become operative, without further action or consent by any person or entity, upon a Change in Control, and once operative shall supersede and control over any other provisions of this Plan. Upon the occurrence of a Change in Control followed within one year of the date of such Change in Control by the participant's cessation of Board membership for any reason, such participant shall be paid the value of his/her Plan Accounts in a single, lump sum cash payment. The value of the Stock Account, which is equal to the number 11 of Stock Units in the Stock Account multiplied by the Fair Market Value on the date of the participant's cessation of Board membership, is transferred to the Cash Account on such date. Earnings are credited to the Cash Account through the date of distribution. The value of the Cash Account that is payable in cash on the date of the single lump sum cash payment is equal to the balance in the Cash Account on the date that is no earlier than five (5) calendar days prior to the day of such distribution. Such payment shall be made as soon as practicable, but in no event later than thirty (30) calendar days after the date of the participant's cessation of Board membership. On or after a Change in Control, no action, including, but not by way of limitation, the amendment, suspension or termination of the Plan, shall be taken which would affect the rights of any participant or the operation of this Plan with respect to the balance in the participant's Plan Accounts. 14. Withholding. CEI may withhold to the extent required by law all applicable income and other taxes from amounts deferred or distributed under the Plan. 15. Copies of Plan Available. Copies of the Plan and any and all amendments thereto shall be made available to all participants during normal business hours at the office of the Plan Administrator. 16. Miscellaneous. (i) Inalienability of benefits - Except as may otherwise be required by law or court order, the interest of each participant or beneficiary under the Plan cannot be sold, pledged, assigned, alienated or transferred in any manner or be subject to attachment or other legal process of whatever nature; provided, however, that any applicable taxes may be withheld from any cash benefit payment made under this Plan. (ii) Controlling law - The Plan and its administration shall be governed by the laws of the State of Maryland, except to the extent preempted by federal law. (iii) Gender and number - A masculine pronoun when used herein refers to both men and women and words used in the singular are intended to include the plural, and vice versa, whenever appropriate. (iv) Titles and headings - Titles and headings to articles and sections in the Plan are placed herein solely for convenience of reference and in any case of conflict, the text of the Plan rather than such titles and headings shall control. 12 (v) References to law - All references to specific provisions of any federal or state law, rule or regulation shall be deemed to also include references to any successor provisions or amendments. (vi) Funding and expenses - Benefits under the Plan are not vested or funded, and shall be paid out of the general assets of CEI. To the extent that any person acquires a right to receive payments from CEI under this Plan, such rights shall be no greater than the right of any unsecured general creditor of CEI. The expenses of administering the Plan will be borne by CEI. (vii) Not a contract - Participation in this Plan shall not constitute a contract of employment or Board membership between CEI and any person and shall not be deemed to be consideration for, or a condition of, continued employment or Board membership of any person. (viii) Successors - In the event CEI becomes a party to a merger, consolidation, sale of substantially all of its assets or any other corporate reorganization in which CEI will not be the surviving corporation or in which the holders of the common stock of CEI will receive securities of another corporation (in any such case, the "New Company"), then the New Company shall assume the rights and obligations of CEI under this Plan. EX-10 5 EXHIBIT 10(M) Exhibit 10(m) Summary Enhanced Retirement Benefits For A Named Executive Officer Under an arrangement with Frank O. Heintz, Baltimore Gas and Electric Company will provide enhanced retirement benefits to Mr. Heintz. Under the arrangement, after he attains age 60 in 2004, Mr. Heintz will be entitled to retirement benefits equal to 40% of total final average salary plus bonus. EX-12 6 EXHIBIT 12 EXHIBIT 12 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 1998 1997 1996 1995 1994 ---------- ---------- ---------- ---------- ----------- (IN MILLIONS OF DOLLARS) Net Income .............................................. $ 327.7 $ 282.8 $ 310.8 $ 338.0 $ 323.6 Taxes on Income ......................................... 181.3 161.5 169.2 172.4 156.7 -------- -------- -------- -------- -------- Adjusted Net Income ..................................... $ 509.0 $ 444.3 $ 480.0 $ 510.4 $ 480.3 -------- -------- -------- -------- -------- Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness ............... $ 255.3 $ 234.2 $ 203.9 $ 206.7 $ 204.2 Capitalized Interest ................................... 3.6 8.4 15.7 15.0 12.4 Interest Factor in Rentals ............................. 1.9 1.9 1.5 2.1 2.0 -------- -------- -------- -------- -------- Total Fixed Charges .................................... $ 260.8 $ 244.5 $ 221.1 $ 223.8 $ 218.6 -------- -------- -------- -------- -------- Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends .................... $ 21.8 $ 28.7 $ 38.5 $ 40.6 $ 39.9 Income Tax Required ................................... 12.0 16.4 20.9 20.4 19.1 -------- -------- -------- -------- -------- Total Preferred and Preference Dividend Requirements ........................................ $ 33.8 $ 45.1 $ 59.4 $ 61.0 $ 59.0 -------- -------- -------- -------- -------- Total Fixed Charges and Preferred and Preference Dividend Requirements .................................. $ 294.6 $ 289.6 $ 280.5 $ 284.8 $ 277.6 -------- -------- -------- -------- -------- Earnings (2) ............................................ $ 766.2 $ 680.4 $ 685.4 $ 719.2 $ 686.5 -------- -------- -------- -------- -------- Ratio of Earnings to Fixed Charges ...................... 2.94 2.78 3.10 3.21 3.14 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements ......... 2.60 2.35 2.44 2.52 2.47
- ---------- (1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings which would be required to meet dividend requirements on preferred stock and preference stock. (2) Earnings are deemed to consist of net income which includes earnings of BGE's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest. 78 EX-21 7 EXHIBIT 21 EXHIBIT 21 SUBSIDIARIES OF THE REGISTRANT*
JURISDICTION OF INCORPORATION ---------------- 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 Safe Harbor Water Power Corporation ........... Pennsylvania BGE Home Products & Services, 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. 79 EX-23 8 EXHIBIT 23 EXHIBIT 23 CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the Registration Statements and Prospectuses of Baltimore Gas and Electric Company on Forms S-8 (File Nos. 33-56084, 33-59545, and 333-45051) and Forms S-3 (File Nos. 33-49801, 33-45260, 33-33559, 33-57658, 333-22697, 333-32311, 333-59601, and 333-66015) of our report dated January 15, 1999 on our audits of the consolidated financial statements and the financial statement schedule of Baltimore Gas and Electric Company as of December 31, 1998 and 1997 and for each of the three years in the period ended December 31, 1998, which report is included in this Annual Report on Form 10-K. /s/ PricewaterhouseCoopers LLP ------------------------------ PRICEWATERHOUSECOOPERS LLP Baltimore, Maryland March 18, 1999 80 EX-27 9 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BGE'S CONSOLIDATED AUDITED FINANCIAL STATEMENTS AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1998, AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000,000 12-MOS DEC-31-1998 JAN-01-1998 DEC-31-1998 PER-BOOK 5,657 1,741 1,176 621 0 9,195 1,485 0 1,490 2,981 0 190 3,128 0 0 0 535 7 0 0 2,354 9,195 3,358 178 2,617 2,795 563 6 569 241 328 22 306 246 248 821 2.06 2.06
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