-----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, CkWypw+xL9DtNOFo0vQLDb2YZOlScSDYn0Fw0d6oFZy/7+Ee8l9CNj1AAQami4VM 5h4iflvw1dbxvy+swKe4tg== 0000950169-00-000347.txt : 20000417 0000950169-00-000347.hdr.sgml : 20000417 ACCESSION NUMBER: 0000950169-00-000347 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20000215 ITEM INFORMATION: ITEM INFORMATION: FILED AS OF DATE: 20000414 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BALTIMORE GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000009466 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 520280210 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-01910 FILM NUMBER: 601557 BUSINESS ADDRESS: STREET 1: 39 W LEXINGTON ST STREET 2: CHARLES CTR CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4102345511 8-K 1 BALTIMORE GAS AND ELECTRIC COMPANY SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): February 15, 2000
Commission IRS Employer File Number Exact name of registrant as specified in its charter Identification No. - ----------- ---------------------------------------------------- ------------------ 1-12869 CONSTELLATION ENERGY GROUP, INC. 52-1964611 1-1910 BALTIMORE GAS AND ELECTRIC COMPANY 52-0280210
Maryland ------------------------------------------------------------------ (State or other jurisdiction of incorporation for each registrant) 250 W. Pratt Street, Baltimore, Maryland 21201 -------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrants' telephone number, including area code: (410) 234-5000 39 W. Lexington Street, Baltimore, Maryland 21201 ------------------------------------------------------------- (Former name or former address, if changed since last report) ITEM 5. Other Events - -------------------- The following financial information for the Company for the year ended December 31, 1999 is set forth in this Form 8-K: Selected Financial Data -- Constellation Energy Group, Inc. and Subsidiaries Selected Financial Data -- Baltimore Gas and Electric Company and Subsidiaries Management's Discussion and Analysis of Financial Condition and Results of Operations Forward Looking Statements Report of Management Report of Independent Accountants Financial Statements Constellation Energy Group, Inc. and Subsidiaries ------------------------------------------------- Consolidated Statements of Income Consolidated Statements of Comprehensive Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Consolidated Statements of Common Shareholders' Equity Consolidated Statements of Capitalization Consolidated Statements of Income Taxes Baltimore Gas and Electric Company and Subsidiaries --------------------------------------------------- Consolidated Statements of Income Consolidated Statements of Comprehensive Income Consolidated Balance Sheets Consolidated Statements of Cash Flows Notes to Consolidated Financial Statements 2 ITEM 7. Financial Statements and Exhibits - ----------------------------------------- (c) Exhibit No. 12(a) Constellation Energy Group, Inc. Computation of Ratio of Earnings to Fixed Charges. Exhibit No. 12(b) Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. Exhibit No. 23 Consent of PricewaterhouseCoopers LLP, Independent Accountants. Exhibit No. 27(a) Constellation Energy Group, Inc. Financial Data Schedule. Exhibit No. 27(b) Baltimore Gas and Electric Company Financial Data Schedule. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. CONSTELLATION ENERGY GROUP, INC. ---------------------------------- (Registrant) BALTIMORE GAS AND ELECTRIC COMPANY ---------------------------------- (Registrant) Date: February 15, 2000 /s/ David A. Brune ---------------------------------- David A. Brune, Vice President on behalf of each Registrant and as Principal Financial Officer of each Registrant 3 SELECTED FINANCIAL DATA - CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES
1999 1998 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions, except per share amounts) SUMMARY OF OPERATIONS Total Revenues $3,786.2 $3,358.1 $3,307.6 $3,153.2 $2,934.8 Operating Expenses 3,026.3 2,617.0 2,584.0 2,483.7 2,239.1 - -------------------------------------------------------------------------------------------------------------- Income From Operations 759.9 741.1 723.6 669.5 695.7 Other Income (Expense) 7.9 5.7 (52.8) 6.1 8.8 - -------------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 767.8 746.8 670.8 675.6 704.5 Fixed Charges 255.0 262.7 258.7 237.0 237.6 - -------------------------------------------------------------------------------------------------------------- Income Before Income Taxes 512.8 484.1 412.1 438.6 466.9 Income Taxes 186.4 178.2 158.0 166.3 169.5 - -------------------------------------------------------------------------------------------------------------- Income Before Extraordinary Item 326.4 305.9 254.1 272.3 297.4 Extraordinary Loss, Net of Income Taxes (66.3) - - - - - -------------------------------------------------------------------------------------------------------------- Net Income $ 260.1 $ 305.9 $ 254.1 $ 272.3 $ 297.4 ============================================================================================================== Earnings Per Share of Common Stock and Earnings Per Share of Common Stock-- Assuming Dilution Before Extraordinary Item $ 2.18 $ 2.06 $ 1.72 $ 1.85 $ 2.02 Extraordinary Loss, Net of Income Taxes (.44) - - - - - -------------------------------------------------------------------------------------------------------------- Earnings Per Share of Common Stock and Earnings Per Share of Common Stock -- Assuming Dilution $ 1.74 $ 2.06 $ 1.72 $ 1.85 $ 2.02 ============================================================================================================== Dividends Declared Per Share of Common Stock $ 1.68 $ 1.67 $ 1.63 $ 1.59 $ 1.55 ============================================================================================================== SUMMARY OF FINANCIAL CONDITION Total Assets $9,683.8 $9,275.0 $8,900.0 $8,678.2 $8,419.1 ============================================================================================================== Capitalization Long-term debt $2,575.4 $3,128.1 $2,988.9 $2,758.8 $2,598.2 Preferred stock - - - - 59.2 Redeemable preference stock - - 90.0 134.5 242.0 Preference stock not subject to mandatory redemption 190.0 190.0 210.0 210.0 210.0 Common shareholders' equity 2,993.0 2,981.5 2,870.4 2,854.7 2,811.2 - -------------------------------------------------------------------------------------------------------------- Total Capitalization $5,758.4 $6,299.6 $6,159.3 $5,958.0 $5,920.6 ============================================================================================================== FINANCIAL STATISTICS AT YEAR END Ratio of Earnings to Fixed Charges 2.87 2.60 2.35 2.44 2.52 Book Value Per Share of Common Stock $ 20.01 $ 19.98 $ 19.44 $ 19.33 $ 19.06 Number of Common Shareholders (In Thousands) 66.1 69.9 73.7 77.6 79.8
Certain prior-year amounts have been reclassified to conform with the current year's presentation. 4 SELECTED FINANCIAL DATA - BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
1999 1998 1997 1996 1995 - ---------------------------------------------------------------------------------------------------------- (Dollar amounts in millions, except per share amounts) SUMMARY OF OPERATIONS Total Revenues $3,028.3 $3,358.1 $3,307.6 $3,153.2 $2,934.8 Operating Expenses 2,324.0 2,617.0 2,584.0 2,483.7 2,239.1 - --------------------------------------------------------------------------------------------------------- Income From Operations 704.3 741.1 723.6 669.5 695.7 Other Income (Expense) 8.4 5.7 (52.8) 6.1 8.8 - --------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 712.7 746.8 670.8 675.6 704.5 Fixed Charges 205.9 240.9 230.0 198.5 197.0 - --------------------------------------------------------------------------------------------------------- Income Before Income Taxes 506.8 505.9 440.8 477.1 507.5 Income Taxes 178.4 178.2 158.0 166.3 169.5 - --------------------------------------------------------------------------------------------------------- Income Before Extraordinary Item 328.4 327.7 282.8 310.8 338.0 Extraordinary Loss, Net of Income Taxes (66.3) - - - - - --------------------------------------------------------------------------------------------------------- Net Income 262.1 327.7 282.8 310.8 338.0 Preferred and Preference Stock Dividends 13.5 21.8 28.7 38.5 40.6 - --------------------------------------------------------------------------------------------------------- Earnings Applicable to Common Stock $248.6 $305.9 $254.1 $272.3 $297.4 ========================================================================================================= SUMMARY OF FINANCIAL CONDITION Total Assets $7,272.6 $9,275.0 $8,900.0 $8,678.2 $8,419.1 ========================================================================================================= Capitalization Long-term debt $2,206.0 $3,128.1 $2,988.9 $2,758.8 $2,598.2 Preferred stock - - - - 59.2 Redeemable preference stock - - 90.0 134.5 242.0 Preference stock not subject to mandatory redemption 190.0 190.0 210.0 210.0 210.0 Common shareholder's equity 2,355.4 2,981.5 2,870.4 2,854.7 2,811.2 - --------------------------------------------------------------------------------------------------------- Total Capitalization $4,751.4 $6,299.6 $6,159.3 $5,958.0 $5,920.6 ========================================================================================================= FINANCIAL STATISTICS AT YEAR END Ratio of Earnings to Fixed Charges 3.45 2.94 2.78 3.10 3.21 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Stock Dividends 3.14 2.60 2.35 2.44 2.52
Certain prior-year amounts have been reclassified to conform with the current year's presentation. 5 Management's Discussion and Analysis of Financial Condition and Results of Operations - ------------------------------------------------ Introduction - ------------ On April 30, 1999, Constellation Energy(R) Group, Inc. (Constellation Energy) became the holding company for Baltimore Gas and Electric Company (BGE(R)) and Constellation(R) Enterprises, Inc. Constellation Enterprises was previously owned by BGE. Constellation Energy's subsidiaries primarily include BGE and a group of energy services businesses focused mostly on power marketing and merchant generation in North America. BGE is an electric and gas public utility company with a service territory that covers the City of Baltimore and all or part of ten counties in Central Maryland. Our energy services businesses are: . Constellation Power Source,(TM) Inc.--wholesale power marketing, . Constellation Power,(TM) Inc. and Subsidiaries--power projects, . Constellation Energy Source,(TM) Inc.--energy products and services, . Constellation Nuclear Group,(TM) LLC--nuclear generation and consulting services, . BGE Home Products & Services,(TM) Inc. and Subsidiaries--home products, commercial building systems, and residential and small commercial gas retail marketing, and . District Chilled Water General Partnership (ComfortLink(R)) --a general partnership, in which BGE is a partner, that provides cooling services for commercial customers in Baltimore. Our other businesses are: . Constellation Investments,(TM) Inc.--financial investments, and . Constellation Real Estate Group,(TM) Inc.--real estate and senior-living facilities. This report is a combined report of Constellation Energy and BGE. The consolidated financial statements of Constellation Energy include the accounts of Constellation Energy, BGE and its subsidiaries, Constellation Enterprises, Inc. and its subsidiaries, and Constellation Nuclear Group, LLC and its subsidiaries. The consolidated financial statements of BGE include the accounts of BGE, ComfortLink, and BGE Capital Trust I. As Constellation Enterprises and its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are included in the consolidated financial statements of BGE through that date. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. References in this report to the "utility business" are to BGE. In this discussion and analysis, we explain the general financial condition and the results of operations for Constellation Energy and BGE including: . what factors affect our business, . what our earnings and costs were in 1999 and 1998, . why earnings and costs changed from the year before, . where our earnings came from, . how all of this affects our overall financial condition, . what our expenditures for capital projects were in 1997 through 1999, and what we expect them to be in 2000 through 2002, and . where we expect to get cash for future capital expenditures. As you read this discussion and analysis, refer to our Consolidated Statements of Income, which present the results of our operations for 1999, 1998, and 1997. We analyze and explain the differences between periods by operating segment. Our analysis is important in making decisions about your investments in Constellation Energy and/or BGE. Also, this discussion and analysis is based on the operation of the electric generation portion of our utility business under current rate regulation. The electric utility industry is undergoing rapid and substantial change. On April 8, 1999, Maryland enacted legislation authorizing customer choice and competition among electric suppliers. On November 10, 1999, the Maryland Public Service Commission (Maryland PSC) issued Order No. 75757 (Restructuring Order) approving a Stipulation and Settlement Agreement between BGE and a majority of the active parties involved in the electric restructuring proceeding that resolves the major issues surrounding electric restructuring. See the "Electric Restructuring" section and Note 4 for a detailed discussion of the Restructuring Order. Our electric business will change significantly beginning July 1, 2000 as we enter into retail customer choice for electric generation and our generation assets are transferred to nonregulated subsidiaries of Constellation Energy. Accordingly, the results of operations and financial condition described in this discussion and analysis are not necessarily indicative of future performance. 6 Strategy - -------- The change toward customer choice will significantly impact our business going forward. In response to this change, we regularly evaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory change. We are realigning our organization combining all of our domestic merchant energy businesses. We will continue to invest in the growth of these businesses, with the objective of providing new sources of earnings in anticipation of lower electric utility revenues. In addition, we might consider one or more of the following strategies: . the complete or partial separation of our transmission and distribution functions, . the construction, purchase or sale of generation assets, . mergers or acquisitions of utility or non-utility businesses, . spin-off or sale of one or more businesses, and . growth of earnings from other 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. However, with the shift toward customer choice, competition, and the growth of our nonregulated subsidiaries, various factors will affect our financial results in the future. These factors include, but are not limited to, operating our currently regulated generation assets in a deregulated market beginning July 1, 2000 without the benefit of a fuel rate adjustment clause, the loss of revenues due to customers choosing alternate suppliers, higher volatility of earnings and cash flows, and increased financial requirements of our nonregulated subsidiaries. Please refer to the "Forward Looking Statements" section for additional factors. Current Issues - -------------- Competition--Electric - --------------------- Electric utilities are facing competition on various fronts, including: . construction of generating units to meet increased demand for electricity, . sale of electricity in bulk power markets, . competing with alternative energy suppliers, and . electric sales to retail customers. On April 8, 1999, Maryland enacted legislation authorizing customer choice and competition among electric suppliers. In addition, on November 10, 1999, the Maryland PSC issued a Restructuring Order that resolved the major issues surrounding electric restructuring. These matters are discussed further in the "Electric Restructuring" section and Note 4. As a result of the deregulation of BGE's electric generation, no earlier than July 1, 2000, and upon receipt of all regulatory approvals, we expect that BGE will transfer, at book value, its nuclear generating assets and its nuclear decommissioning trust fund to a subsidiary of Constellation Nuclear Group, LLC. In addition, we expect that BGE will transfer, at book value, its fossil generating assets and its partial ownership interest in two coal plants and a hydroelectric plant located in Pennsylvania to a nonregulated subsidiary of Constellation Energy. In total, these generating assets represent about 6,240 megawatts of generation capacity with a total projected net book value at June 30, 2000 of approximately $2.4 billion. We expect BGE to transfer approximately $278 million of tax exempt debt to our nonregulated subsidiaries related to the transferred assets and that BGE will receive approximately $1.1 billion in unsecured promissory notes. Repayments of the notes by our nonregulated subsidiaries will be used exclusively to service certain long-term debt of BGE. BGE will also transfer equity associated with the generating assets to nonregulated subsidiaries of Constellation Energy. Under the Restructuring Order, BGE will provide standard offer service to customers at fixed rates over various time periods during the transition period for those customers that do not choose an alternate supplier once customer choice begins July 1, 2000. In addition, the electric fuel rate will be discontinued effective July 1, 2000. Nonregulated subsidiaries of Constellation Energy will provide BGE with the energy and capacity required to meet its standard offer service obligations for the first three years of the transition period. Standard offer service will be competitively bid thereafter. Nonregulated subsidiaries of Constellation Energy will obtain the energy and capacity to supply BGE's standard offer service obligations from the Calvert Cliffs Nuclear Power Plant (Calvert Cliffs) and BGE's former fossil plants, supplemented with energy purchased from the wholesale energy market as necessary. Our earnings will be exposed to the risks of the competitive wholesale electricity market to the extent that our nonregulated subsidiaries have to purchase energy and/or capacity or generate energy to meet obligations to supply power to BGE at market prices or costs, respectively, which may approach or exceed 7 BGE's standard offer service rates. We will also be affected by operational risk, that is, the risk that a generating plant is not available to produce energy when the energy is required. Until July 1, 2000, we will continue 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. After July 1, 2000, any energy purchased to meet BGE's load commitments will become a cost of doing business in the newly competitive marketplace. Therefore, if BGE provides standard offer service at fixed rates to its customers that do not select an alternative provider as required under the terms of the Restructuring Order, and the load demand exceeds our capacity to supply energy due to a plant outage, we would be required to purchase additional power in the wholesale energy market. If the price of obtaining energy in the wholesale market exceeds the fixed standard offer service price, our earnings would be adversely affected. Imbalances in demand and supply can occur not only because of plant outages, but also because of transmission constraints or due to extreme temperatures (hot or cold) causing demand to exceed available supply. We will use appropriate risk management techniques consistent with our business plan and policies to address these issues. We cannot estimate the impact of the increased financial risks associated with this transition. However, these financial risks could have a material impact on our, and BGE's, financial results. Competition--Gas - ---------------- Currently, no regulation exists for the wholesale price of natural gas as a commodity, and the regulation of interstate transmission at the federal level has been reduced. All BGE industrial and commercial gas customers, and effective November 1, 1999, all BGE residential customers have the option to purchase gas from other suppliers. Early Retirement Program - ------------------------ In recognition of the changing business environment, in 1999, our Board of Directors approved a Targeted Voluntary Special Early Retirement Program (TVSERP) to provide enhanced early retirement benefits to certain eligible participants in targeted jobs that elect to retire on June 1, 2000. The financial impacts of the TVSERP will be reflected in the second quarter of 2000. Calvert Cliffs License Extension - -------------------------------- In 1998, we filed an application with the Nuclear Regulatory Commission (NRC) for a 20-year license extension for Calvert Cliffs 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. According to the NRC's timetable, approval of BGE's application is expected in April 2000. However, we cannot predict the actual timing of the NRC's decision, or the impact, if any, on our financial results. If we do not receive the license extension, we may not be able to operate the Calvert Cliffs units beyond 2014 and 2016. BGE is currently involved in a lawsuit titled National Whistleblower Center v. Nuclear Regulatory Commission and Baltimore Gas and Electric Company regarding its license extension process. The matter involves an appeal of the NRC's dismissal of Whistleblower's petition to intervene in the license renewal proceeding. At issue was the NRC's adoption of a streamlined procedure for the proceeding, including the requirement that any requests for extensions of time be justified by a showing of "unavoidable and extreme circumstances" rather than the "good cause" standard previously applied. Applying the new standard, the NRC ultimately dismissed Whistleblower's petition to intervene. This matter is pending before the court. Environmental and Legal Matters - ------------------------------- You will find details of our environmental matters in Note 10 and in our most recent Annual Report on Form 10-K under Item 1. Business--Environmental Matters. You will find details of our legal matters in our most recent Annual Report on Form 10-K under Item 3. Legal Proceedings. Some of the information is about costs that may be material to our financial results. Year 2000 - --------- We did not experience any significant problems associated with the year 2000 issue. Accounting Standards Issued - --------------------------- We discuss recently issued accounting standards in Note 1. 8 Results of Operations - --------------------- In this section, we discuss our earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for our operating segments. Overview - -------- Total Earnings Per Share of Common Stock 1999 1998 1997 - ------------------------------------------------------------------------- Utility business $2.03 $1.93 $1.94 Diversified businesses .45 .27 .34 - ------------------------------------------------------------------------- Total earnings per share before nonrecurring charges included in operations 2.48 2.20 2.28 Nonrecurring charges included in operations Hurricane Floyd (see Note 2) (.03) - - Write-off of merger costs (see Note 2) - - (.25) Write-downs of power projects (see Note 3) (.12) - - Write-off of energy services investment (see Note 2) - (.04) - Write-down of financial investment (see Note 3) (.11) - - Write-downs of real estate and senior-living investments (see Note 2 and Note 3) (.04) (.10) (.31) - ------------------------------------------------------------------------- Total earnings per share before extraordinary item 2.18 2.06 1.72 - ------------------------------------------------------------------------- Extraordinary loss (see Note 4) (.44) - - - ------------------------------------------------------------------------- Total earnings per share $1.74 $2.06 $1.72 ========================================================================= 1999 - ---- Our 1999 total earnings decreased $45.8 million, or $.32 per share, compared to 1998. Our total earnings decreased mostly because we recorded an extraordinary charge of $66.3 million, or $.44 per share, associated with the deregulation of the electric generation portion of our business. Our 1999 total earnings also include nonrecurring write-downs recorded in our power projects, financial investments, and real estate and senior-living businesses. These decreases were partially offset by higher earnings from utility and diversified business operations excluding nonrecurring charges. We discuss the extraordinary charge in Note 4. In 1999, we had higher utility earnings before the extraordinary charge compared to 1998 mostly because we sold more electricity and gas this year, and we settled a capacity contract with PECO Energy Company in 1998 that had a negative impact on earnings in that year. This increase was partially offset by storm restoration activities related to Hurricane Floyd and higher depreciation and amortization expense mostly due to the $75.0 million, or $48.8 million after- tax, amortization of the regulatory asset recorded in 1999 for the reduction of our generation plant under the Restructuring Order. We discuss our utility earnings and the Restructuring Order in more detail in the "Utility Business" section. In 1999, diversified business earnings before nonrecurring charges increased compared to 1998 mostly because of higher earnings from our power marketing business. We discuss our diversified business earnings, including the write-downs, further in the "Diversified Businesses" section. 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 costs associated with the terminated merger with Potomac Electric Power Company, and our real estate and senior-living facilities business' write- down of its investments in two real estate projects. This increase was partially offset by: . our real estate and senior-living facilities business' write-down of its investment in a real estate project in 1998, and . the write-off of an energy services investment in 1998. In 1998, utility earnings were about the same compared to 1997. In 1998, diversified business earnings before nonrecurring charges decreased compared to 1997 mostly because of lower earnings from our real estate and senior-living facilities and financial investments businesses. This decrease was partially offset by higher earnings from our power projects and power marketing businesses. 9 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: electric restructuring, regulation by the Maryland PSC, the weather, and other factors, including the condition of the economy in our service territory. Electric Restructuring - ---------------------- On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that will significantly restructure Maryland's electric utility industry and modify the industry's tax structure. In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The accompanying tax legislation is discussed in detail in Note 4. On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolves the major issues surrounding electric restructuring, accelerates the timetable for customer choice, and addresses the major provisions of the Act. The Restructuring Order also resolves the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. The major provisions of the Restructuring Order are: . All customers, except a few commercial and industrial companies that have signed contracts with BGE, will be able to choose their electric energy supplier beginning July 1, 2000. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE. . BGE's current electric base rates are frozen at their current levels until July 1, 2000. . BGE will reduce residential base rates by approximately 6.5% on average, about $54 million a year, beginning July 1, 2000. These rates will not change before July 2006. . Commercial and industrial customers will have up to four service options that will fix electric energy rates and transition charges for a period that generally ranges from four to six years. . Electric delivery service rates will be frozen for a four-year period for commercial and industrial customers. The generation and transmission components of rates will be frozen for different time periods depending on the service options selected by those customers through June 30, 2004. . BGE will be allowed to recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through a competitive transition charge on customers' bills. Residential customers will pay this charge for six years. Commercial and industrial customers will pay in a lump sum or over the four to six-year period, depending on the service option selected by each customer. . Generation-related regulatory assets and nuclear decommissioning costs will be included in delivery service rates effective July 1, 2000 and will be recovered on a basis approximating their existing amortization schedules. . Starting July 1, 2000, BGE will unbundle rates to show separate components for delivery service, transition charges, standard offer service (generation), transmission, universal service, and taxes. . On July 1, 2000, BGE will transfer, at book value, its ten Maryland-based fossil and nuclear power plants and its partial ownership interest in two coal plants and a hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy. . BGE will reduce its generation assets, as discussed in Note 4, by $150 million pre-tax during the period July 1, 1999 - June 30, 2000 to mitigate a portion of its potentially stranded investments. . Universal service will be provided for low-income customers without increasing their bills. BGE will provide its share of a statewide fund totaling $34 million annually. We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises-- Accounting for the Discontinuation of FASB Statement No. 71 and Emerging Issues Task Force Consensus (EITF) No. 97-4, Deregulation of the Pricing of Electricity--Issues Related to the Application of FASB Statements No. 71 and 101 for BGE's electric generation business. BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated. We describe the effect of applying these accounting requirements in Note 4. In early December, the Mid-Atlantic Power Supply Association (MAPSA), Trigen- Baltimore Energy Corporation, and Sweetheart Cup Company, Inc. filed appeals of the Restructuring Order. MAPSA also filed a motion seeking to delay the implementation of the Restructuring Order pending 10 a decision on the merits by the court. While we believe that the appeals are without merit, no assurances can be given as to the timing or outcome of these cases, and whether the outcome will have a material adverse effect on our and BGE's financial results. Regulation by the Maryland PSC - ------------------------------ Under traditional rate regulation that will continue for all BGE's businesses except electric generation beginning July 1, 2000, the Maryland PSC determines the rate we can charge our customers. Our rates consist of a "base rate," a "conservation surcharge," and a "fuel rate." Base 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 higher. Gas base rates are not affected by seasonal changes. Except as provided under the terms of the electric Restructuring Order discussed above, BGE may ask the Maryland PSC to increase base rates from time to time. The Maryland PSC historically has allowed BGE to increase base rates to recover increased utility plant asset costs, plus a profit, beginning at the time of replacement. Generally, rate increases improve our utility earnings because they allow us to collect more revenue. However, rate increases are normally granted based on historical data and those increases may not always keep pace with increasing costs. Other parties may petition the Maryland PSC to decrease base rates. On November 17, 1999, BGE filed an application with the Maryland PSC to increase its gas base rates. We discuss this filing in the gas "Base Rate" section. Conservation Surcharge - ---------------------- The Maryland PSC allows us to include in electric and gas 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 (include as a liability on 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. As a result of the Restructuring Order, the electric conservation surcharge was frozen at its current level and the associated profit limitation is no longer applicable. Fuel Rate - --------- Currently, 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. We charge the actual cost of these items to the customer with no profit to us. If these 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 mostly impacted by the amount of electricity generated at Calvert Cliffs because the cost of nuclear fuel is cheaper than coal, gas, or oil. Under the Restructuring Order, BGE's electric fuel rate is frozen at its current level until July 1, 2000, at which time the fuel rate clause will be discontinued. We will continue to defer the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate through June 30, 2000. After that date, earnings will be affected by the changes in the cost of fuel and energy. We discuss our exposure to market risk further in the "Current Issues" section. In addition, any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC. At December 31, 1999, the amount to be collected from customers was $60.0 million. We charge our gas customers separately for the natural gas they purchase from us. The price we charge for the natural gas is based on a market based rates incentive mechanism approved by the Maryland PSC. We discuss market based rates in more detail in the "Gas Cost Adjustments" section and in Note 1. 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. 11 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 1999 and 1998, the percentage change in the number of degree days from the prior year, and the number of degree days in a "normal" year as represented by the 30-year average in the following table.
30-year 1999 1998 average - ------------------------------------------------------------------------- Cooling degree days 845 915 843 Percentage change from prior year (7.7)% 22.7% Heating degree days 4,585 4,119 4,755 Percentage change from prior year 11.3% (14.6)%
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 1999 and 1998. 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. When customer choice for electric generation begins on July 1, 2000, a portion of BGE's electric customers will become delivery service customers only and will purchase their electricity from other sources. Other electric customers will receive standard offer service from BGE at the fixed rates provided by the Restructuring Order. To the extent our electricity generation exceeds or is less than the electricity demanded by customers utilizing our standard offer service, the incremental electricity will be sold or purchased in the wholesale market at prevailing market prices. We discuss our exposure to market risk further in the "Current Issues" section. Usage per customer refers to all other items impacting customer sales that cannot be measured separately. These factors include the strength of the economy in our service territory. When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downtrend, our customers tend to consume less electricity and gas. Utility Business Earnings Per Share of Common Stock - ---------------------------------------------------
1999 1998 1997 - --------------------------------------------------------------------- Electric business $1.81 $1.75 $1.77 Gas business .22 .18 .17 - --------------------------------------------------------------------- Total utility earnings per share before nonrecurring charge included in operations 2.03 1.93 1.94 Nonrecurring charge included in operations: Hurricane Floyd (see Note 2) (.03) - - Write-off of merger costs (see Note 2) - - (.25) - --------------------------------------------------------------------- Total utility earnings per share before extraordinary item 2.00 1.93 1.69 - --------------------------------------------------------------------- Extraordinary loss (see Note 4) (.44) - - - --------------------------------------------------------------------- Total utility earnings per share $1.56 $1.93 $1.69 =====================================================================
Our 1999 total utility earnings decreased $53.9 million, or $.37 per share, compared to 1998. Our 1998 total utility earnings increased $36.1 million, or $.24 per share, compared to 1997. We discuss the factors affecting utility earnings below. Electric Operations - ------------------- The discussion below reflects the operations of the electric generation portion of our utility business under current rate regulation by the Maryland PSC. Our electric business will change significantly beginning July 1, 2000 as we enter into retail customer choice for electric generation. Also, no earlier than July 1, 2000, and upon receipt of all regulatory approvals, all of BGE's generation assets will be transferred, at book value, to nonregulated subsidiaries of Constellation Energy. These assets represent about 6,240 megawatts of generation capacity with a total projected net book value at June 30, 2000 of approximately $2.4 billion. 12 We estimate that the electric generation portion of our business currently represents about one-half of BGE's operating income. We expect BGE to transfer approximately $278 million of tax exempt debt to our nonregulated subsidiaries related to the transferred assets and that BGE will receive approximately $1.1 billion in unsecured promissory notes. Repayments of the notes by our nonregulated subsidiaries will be used exclusively to service certain long-term debt of BGE. BGE will also transfer equity associated with the generating assets to nonregulated subsidiaries of Constellation Energy. Given the uncertainties surrounding electric deregulation as discussed in the "Strategy" and "Current Issues" sections, the results discussed in this section may not be indicative of the future performance of our generation business. Also, these results will not be indicative of the future performance of BGE once BGE transfers all of its generation assets to nonregulated subsidiaries of Constellation Energy. The impact of this transfer on BGE's financial results will be material. The total assets, liabilities, and common shareholders' equity of Constellation Energy will not change as a result of the transfer. Electric Revenues - ----------------- The changes in electric revenues in 1999 and 1998 compared to the respective prior year were caused by: 1999 1998 - ------------------------------------------------------------------------------- (In millions) Electric system sales volumes $41.2 $50.8 Base rates 0.8 (6.6) Fuel rates 3.7 (8.1) - -------------------------------------------------------------------------------- Total change in electric revenues from electric system sales 45.7 36.1 Interchange and other sales (8.2) (13.2) Other 2.1 4.6 - -------------------------------------------------------------------------------- Total change in electric revenues $39.6 $27.5 ================================================================================ Electric System Sales Volumes - ----------------------------- "Electric system sales volumes" are sales to customers in our service territory at rates set by the Maryland PSC. These sales do not include interchange sales and sales to others. The percentage changes in our electric system sales volumes, by type of customer, in 1999 and 1998 compared to the respective prior year were: 1999 1998 - ------------------------------------------------------------------------------ Residential 3.5% 1.5% Commercial 2.6 3.9 Industrial (5.1) 0.2 In 1999, we sold more electricity to residential customers due to higher usage per customer, colder winter weather, and an increased number of customers. This increase was partially offset by milder spring and early summer weather. We sold more electricity to commercial customers mostly due to higher usage per customer, an increased number of customers, and colder winter weather. We sold less electricity to industrial customers mostly because usage by Bethlehem Steel and other industrial customers decreased. Usage decreased at Bethlehem Steel as a result of a shut-down from June to August for an upgrade to their facilities that temporarily reduced their electricity consumption. This decrease was partially offset by an increase in the number of industrial customers. In 1998, we sold more electricity to residential customers mostly because of an increased number of customers, hotter summer weather, and higher usage per customer. The increase in sales to residential customers was partially offset by milder winter weather. We sold more electricity to commercial customers mostly because of higher usage per customer. We sold about the same amount of electricity to industrial customers as we did in 1997. Base Rates - ---------- In 1999, base rate revenues were about the same compared to 1998. 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. Fuel Rates - ---------- In 1999, fuel rate revenues increased compared to 1998 mostly because we sold more electricity. 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. 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 other utility companies. We sell energy to PJM members and to others after we have satisfied the demand for electricity in our own system. 13 In 1999 and 1998, interchange and other sales revenues decreased compared to the respective prior year mostly because higher demand for system sales reduced the amount of energy we had available for off-system sales. Electric Fuel and Purchased Energy Expenses - ------------------------------------------- 1999 1998 1997 - -------------------------------------------------------------------------------- (In millions) Actual costs $538.0 $514.7 $504.5 Net (deferral) recovery of costs under electric fuel rate clause (see Note 1) (70.3) (9.0) 15.2 - -------------------------------------------------------------------------------- Total electric fuel and purchased energy expenses $467.7 $505.7 $519.7 =============================================================================== Actual Costs - ------------ In 1999, our actual costs of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from others were higher compared to 1998 mostly because the price of electricity we bought from others was higher. The price of electricity changes based on market conditions and contract terms. This increase was partially offset by our settlement of a capacity contract with PECO in 1998. In 1998, our actual costs increased compared to 1997 mostly because we settled a capacity contract with PECO. 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 and its future discontinuance in Note 1. In 1999 and 1998, our actual costs of fuel and energy were higher than the fuel rate revenues we collected from our customers. The increase in the 1999 deferral reflects higher purchased power costs, especially during record-setting summer peak loads. Electric Operations and Maintenance Expenses - -------------------------------------------- In 1999, electric operations and maintenance expenses were about the same compared to 1998. In 1999, operations and maintenance expenses include the costs for system restoration activities related to Hurricane Floyd of $7.5 million and a major winter ice storm. This was offset by lower employee benefit costs in 1999 and a 1998 $6.0 million write-off of contributions to a third party for a low-level radiation waste facility that was never completed. In 1998, electric operations and maintenance expenses increased $28.7 million compared to 1997 mostly because of: . higher nuclear costs, . higher employee benefit costs, and . the $6.0 million write-off for the low-level radiation waste facility discussed above. Electric Depreciation and Amortization Expense - ---------------------------------------------- In 1999, electric depreciation and amortization expense increased $63.4 million compared to 1998 mostly because of the $75.0 million amortization of the regulatory asset for the reduction in generation plant provided for in the Restructuring Order. This increase was partially offset by lower amortization of deferred electric conservation expenditures due to the write-off of a portion of these expenditures that will not be recovered under the Restructuring Order. We discuss the accounting implications of the Restructuring Order further in Note 4. In 1998, electric depreciation and amortization expense increased $26.5 million compared to 1997 mostly because: . 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, . we had more electric plant in service (as our level of plant in service changes, the amount of our depreciation and amortization expense changes), and . we reduced the amortization period for certain computer software beginning in the first quarter of 1998 from five years to three years. 14 Gas Operations - -------------- All BGE industrial and commercial gas customers, and effective November 1, 1999, all BGE residential customers have the option to purchase gas from other suppliers. We do not expect the impact of customer choice to have a material effect on our, and BGE's, financial results. Gas Revenues - ------------ The changes in gas revenues in 1999 and 1998 compared to the respective prior year were caused by: 1999 1998 - ------------------------------------------------------------------ (In millions) Gas system sales volumes $ 8.0 $(10.8) Base rates 2.2 14.2 Weather normalization 4.5 10.1 Gas cost adjustments 19.8 (87.6) - ------------------------------------------------------------------ Total change in gas revenues from gas system sales 34.5 (74.1) Off-system sales (7.9) 1.8 Other 0.5 0.1 - ------------------------------------------------------------------ Total change in gas revenues $ 27.1 $(72.2) ================================================================== Gas System Sales Volumes - ------------------------ The percentage changes in our gas system sales volumes, by type of customer, in 1999 and 1998 compared to the respective prior year were: 1999 1998 - -------------------------------------------------------------- Residential 9.2% (11.6)% Commercial 12.7 (9.5) Industrial (4.8) (11.3) In 1999, we sold more gas to residential customers mostly for two reasons: colder winter weather and an increased number of customers. This was partially offset by lower usage per customer. We sold more gas to commercial customers mostly because of higher usage per customer, colder winter weather, and an increased number of customers. We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers. Usage by Bethlehem Steel decreased due to a shut-down from June to August for an upgrade to their facilities. In 1998, we sold less gas to residential and commercial customers mostly for two reasons: milder weather and lower usage per customer. This was partially offset by the increase in the number of customers. We sold less gas to industrial customers mostly because of lower usage by Bethlehem Steel and other industrial customers. Base Rates - ---------- In 1999, base rate revenues increased compared to 1998 mostly due to the increase in our base rates effective March 1, 1998 as discussed below. 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 increased our base rate revenues over the twelve-month period from March 1998 through February 1999 by approximately $16 million. On November 17, 1999, we applied for a $36.3 million annual increase in our gas base rates. The Maryland PSC is currently reviewing our application and is expected to issue an order by June 2000. Weather Normalization - --------------------- Effective March 1, 1998, the Maryland PSC allowed us to implement a monthly adjustment to our gas revenues to eliminate the effect of abnormal weather patterns on our gas system sales volumes. This means our monthly gas revenues 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 similarly to the electric fuel rate clause described in the "Electric Fuel Rate Clause" section. However, under market based rates, our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers, and does not significantly impact earnings. 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 the same as the base rate charged for gas sales and are included in gas system sales volumes. In 1999, gas cost adjustment revenues increased compared to the same period of 1998 mostly because we sold more gas at a higher price. In 1998, gas cost adjustment revenues decreased compared to 1997 mostly because we sold less gas. 15 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 1999, revenues from off-system gas sales decreased compared to 1998 mostly because we sold less gas off-system. In 1998, revenues from off-system gas sales increased compared to 1997 mostly because we sold more gas off-system. Gas Purchased For Resale Expenses - --------------------------------- 1999 1998 1997 - -------------------------------------------------------------- (In millions) Actual costs $221.8 $212.2 $291.6 Net recovery (deferral) of costs under gas adjustment clauses (see Note 1) 8.8 (3.6) 0.5 - -------------------------------------------------------------- Total gas purchased for resale expenses $230.6 $208.6 $292.1 ============================================================== 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 1999, actual gas costs increased compared to 1998 mostly because we sold more gas. In 1998, actual gas costs decreased compared to 1997 mostly because we sold less gas. 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 1999, actual gas costs were lower than the fuel rate revenues we collected from our customers. In 1998, actual gas costs were higher than the fuel rate revenues we collected from our customers. Gas Operations and Maintenance Expenses - --------------------------------------- In 1999, gas operations and maintenance expenses were about the same compared to 1998. In 1998, gas operations and maintenance expenses increased $3.9 million compared to 1997 mostly because of higher employee benefit costs. Gas Depreciation and Amortization Expense - ----------------------------------------- In 1999, gas depreciation and amortization expense was about the same compared to 1998. In 1998, gas depreciation and amortization expense increased $6.1 million compared to 1997 mostly because: . we had more gas plant in service, and . we reduced the amortization period for certain computer software beginning in the first quarter of 1998 from five years to three years. 16 Diversified Businesses - ---------------------- Our diversified businesses engage primarily in energy services. We list each of our diversified businesses in the "Introduction" section. We describe our diversified businesses in more detail in our most recent Annual Report on Form 10-K under "Item 1. Business - Diversified Businesses." Diversified Business Earnings Per Share of Common Stock - ----------------------------- 1999 1998 1997 - ----------------------------------------------------------------------- Energy services Power marketing $ .23 $ .05 $ - Power projects .26 .30 .25 Other (.05) (.01) (.05) - ----------------------------------------------------------------------- Total energy services earnings per share before nonrecurring charges included in operations .44 .34 .20 Other diversified businesses earnings (losses) per share before nonrecurring charges included in operations .01 (.07) .14 - ----------------------------------------------------------------------- Total diversified businesses earnings per share before nonrecurring charges included in operations .45 .27 .34 Nonrecurring charges included in operations: Write-downs of power projects (see Note 3) (.12) - - Write-off of energy services investment (see Note 2) - (.04) - Write-down of financial investment (see Note 3) (.11) - - Write-downs of real estate and senior-living investments (see Note 2 and Note 3) (.04) (.10) (.31) - ----------------------------------------------------------------------- Total earnings per share $ .18 $ .13 $ .03 ======================================================================= Our 1999 diversified business earnings increased $8.1 million, or $.05 per share, compared to 1998. Our 1998 diversified business earnings increased $15.7 million, or $.10 per share, compared to 1997. We discuss factors affecting the earnings of our diversified businesses below. Energy Services - --------------- Power Marketing - --------------- In 1999, earnings from our power marketing business increased compared to 1998 because of increased transaction margins and volume. In 1998, earnings from our power marketing business increased compared to 1997 because of increased power marketing 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. We discuss the mark-to-market method of accounting and Constellation Power Source's activities in Note 1. As a result of the nature of its business 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: . the number and size of new transactions, . the magnitude and volatility of changes in commodity prices and interest rates, and . the number and size of open commodity and derivative positions Constellation Power Source holds or sells. Constellation Power Source's management uses its best estimates to determine the fair value of commodity and derivative positions it holds and sells. These estimates consider various factors including closing exchange and over-the- counter price quotations, time value, volatility factors, and credit exposure. However, it is possible that future market prices could vary from those used in recording assets and liabilities from power marketing and trading activities, and such variations could be material. In 1999, assets and liabilities from energy trading activities (as shown in our Consolidated Balance Sheets) increased because of greater business activity during the period. In March 1998, we formed Orion Power Holdings, Inc. (Orion) with Goldman, Sachs Capital Partners II L.P., an affiliate of Goldman, Sachs & Co., to acquire electric generating plants in the United States and Canada. Our energy services businesses own a minority interest in Orion. To date, our energy services businesses have funded $104 million in equity and have a commitment to contribute an additional $121 million to Orion. 17 Power Projects - -------------- In 1999, earnings from our power projects business decreased compared to 1998 mostly because of three factors: . In 1999, our power projects business recorded a $14.2 million after-tax, or $.09 per share, write-off of two geothermal power projects. These write-offs occurred because the expected future cash flows from the projects are less than the investment in the projects. For the first project, this resulted from the inability to restructure certain project agreements. For the second project, we experienced a declining water temperature of the geothermal resource used by one of the plants for production. . In 1999, our power projects business recorded a $4.5 million after-tax, or $.03 per share, write-down to reflect the fair value of our investment in a power project as a result of our international exit strategy discussed later in this section. . In 1998, our power projects business recorded a $10.4 million after-tax, or $.07 per share, gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of its ownership interest in a power purchase agreement. 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 as discussed above. California Power Purchase Agreements - ------------------------------------ Constellation Power and subsidiaries and Constellation Investments have $301.8 million invested in 14 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. In 1999, earnings from these projects, excluding any write-offs, were $34.4 million, or $.23 per share, compared to $41.3 million, or $.28 per share in 1998. 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. As of December 31, 1999, ten projects had already transitioned to variable rates. The remaining four projects will transition between February and December 2000. The projects which transitioned in 1999 contributed $6.2 million, or $.04 per share to 1999 earnings. Those changing over in 2000 contributed $28.0 million, or $.19 per share to 1999 earnings. We expect earnings from the projects changing over in 2000 to contribute $17.4 million, or $.12 per share to 2000 earnings. Our power projects business continues to pursue alternatives for some of these projects including: . repowering the projects to reduce operating costs, . changing fuels to reduce operating costs, . renegotiating the power purchase agreements to improve the terms, . restructuring financing to improve existing terms, and . selling its ownership interests in the projects. We evaluate the carrying amount of our investment in these projects for impairment using the methodology discussed in Note 1. Constellation Power's management uses its best estimates to determine if there has been an impairment of these investments and considers various factors including forward price curves for energy, fuel costs, and operating costs. However, it is possible that future estimates of market prices and project costs could vary from those used in evaluating these assets, and the impact of such variations could be material. We also describe these projects and the transition process in Note 10. International Projects - ---------------------- At December 31, 1999, Constellation Power had invested about $254.1 million in 10 power projects in Latin America compared to $269.7 million invested in Latin America in 1998. These investments include: . 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 . approximately $98 million for the purchase of existing electric generation facilities and the construction of an electric generation facility in Guatemala. 18 In December 1999, we decided to exit the international portion of our power projects business as part of our strategy to improve our competitive position. As a result, we recorded a $4.5 million after-tax write-down of our investment in a generating company in Bolivia to reflect the current fair value of this investment. We expect to complete our exit strategy by the end of 2000. We discuss our strategy further in the "Strategy" section. Other Energy Services - --------------------- In 1999, earnings from our other energy services businesses decreased compared to 1998 mostly because of lower gross margins at our energy products and services business. In 1998, earnings from our other 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. Other Diversified Businesses - ---------------------------- In 1999, earnings from our other diversified businesses increased compared to 1998 mostly because of higher earnings from our real estate and senior-living facilities business. This increase was partially offset by lower earnings from our financial investments business. In 1999, earnings from our real estate and senior-living facilities business increased compared to 1998 mostly because of: . a $15.4 million after-tax write-down of its investment in Church Street Station, an entertainment, dining, and retail complex in Orlando, Florida in 1998, and . an increase in earnings from its investment in Corporate Office Properties Trust (COPT) in 1999. We discuss the investment in COPT below. This increase was partially offset by a $5.8 million after-tax, or $.04 per share, write-down of certain senior-living facilities related to the proposed sale of these facilities in 1999 as discussed below. In 1999, our senior-living facilities business entered into an agreement to sell all but one of its senior-living facilities to Sunrise Assisted Living, Inc. Under the terms of the agreement, Sunrise was to acquire 12 of our existing senior-living facilities, three facilities under construction, and several sites under development for $72.2 million in cash and $16.0 million in debt assumption. We could not reach an agreement on financing issues that subsequently arose, and the agreement was terminated in November 1999. As a result, our senior-living facilities business engaged a third-party management company to manage its senior-living facilities portfolio including the three facilities now under construction, scheduled to be completed in the first half of 2000. In 1999, Constellation Real Estate Group, Inc. (CREG) sold Church Street Station, for $11.5 million, the approximate book value of the complex. In 1999, our financial investments business announced that it would exchange its shares of common stock in Capital Re, an insurance company, for common stock of ACE Limited (ACE), another insurance company, as part of a business combination whereby ACE would acquire all of the outstanding capital stock of Capital Re. Through September 30, 1999, our financial investments business wrote down its $94.2 million investment in Capital Re stock by $20.9 million after-tax, or $.14 per share, to reflect the market value of this investment. The agreement between ACE and Capital Re was subsequently revised on a more favorable basis for Capital Re to include both cash and ACE stock. In December 1999, the transaction was finalized and our financial investments business recorded a $4.9 million after-tax, or $.03 per share, gain on this investment to reflect the closing price of the business combination. This net write-down of Capital Re was partially offset by better market performance of other financial investments in 1999 compared to 1998. In 1998, earnings from our other diversified businesses decreased compared to 1997 mostly due to 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 mostly due to: . a $15.4 million after-tax write-down of its investment in Church Street Station, . lower earnings from various real estate and senior-living facilities projects, and . a $4.0 million after-tax gain on the sale of two senior-living facilities projects reflected in 1997 results. 19 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 COPT, a real estate investment trust. In 1998, earnings from our financial investments business decreased compared to 1997 mostly because of: . better market performance for its investments in 1997, and . a $6.0 million after-tax gain on the sale of stock held by a financial limited partnership reflected in 1997 results. 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. Most of CREG's remaining 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. Constellation Real Estate's projects have continued to incur carrying costs and depreciation over the years. Additionally, this business 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 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 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. Our current real estate strategy is to hold each real estate project until we can realize a reasonable value for it. We evaluate strategies for all our 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 business strategies on a regular basis so we use capital and other resources in a manner that is most beneficial. Under accounting rules, we are required to write down the value of a real estate project to market value in either of two cases. The first is if we change our intent about a project from an intent to hold to an intent to sell and the market value of that project is below book value. The second is if the expected future cash flow from the project is less than the investment in the project. Consolidated Nonoperating Income and Expenses - --------------------------------------------- Other Income and Expenses - ------------------------- In September 1995, we signed an agreement to merge with Potomac Electric Power Company 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. Fixed Charges - ------------- In 1999, fixed charges decreased $7.7 million compared to 1998 mostly because we had less BGE preference stock outstanding. In 1998, fixed charges increased $4.0 million compared to 1997 mostly because we had more debt outstanding. Our fixed charges would have been higher except we had less BGE preference stock outstanding and lower interest rates in 1998 compared to 1997. Income Taxes - ------------ In 1999, income taxes increased $8.2 million compared to 1998 because we had higher taxable income from both our utility operations and our diversified businesses. 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. Please refer to Note 4 for a discussion of tax law changes. These changes are designed, in part, to tax Maryland electric generating facilities on a more comparable basis with electric generation in other states. 20 Financial Condition - ------------------- Cash Flows - ---------- 1999 1998 1997 - ----------------------------------------------------------- (In millions) Cash provided by (used in): Operating Activities $ 679.0 $ 799.8 $ 696.3 Investing Activities (615.1) (711.3) (520.8) Financing Activities (144.9) (77.4) (79.6) In 1999 and 1998, cash provided by operations changed compared to the respective prior year mostly because of changes in working capital requirements. In 1999, we used less cash for investing activities compared to 1998 mostly due to lower investments in international power projects and in the real estate and senior-living facilities business. This was partially offset by: . our energy services businesses increased the investment in Orion Power Holdings, Inc. by $97.7 million, . our power projects business increased its investment in domestic power projects, primarily related to the 800 megawatts of peaking capacity as discussed in the "Capital Requirements of our Diversified Businesses" section, and . BGE increased its construction expenditures by $46.5 million. In 1998, net cash used in investing activities increased compared to 1997 mostly because of the additional investments in international power projects. This was partially offset by a $33.8 million decrease in utility construction expenditures. Total utility construction expenditures, including the allowance for funds used during construction, were $385.9 million in 1999 as compared to $339.4 million in 1998 and $373.2 million in 1997. In 1999, we used more cash for financing activities compared to 1998 mostly because we repaid more long-term debt and issued less long-term debt and common stock. This was partially offset by a decrease in the redemption of BGE preference stock and higher net short-term borrowings in 1999 compared to 1998. In 1998, cash used in financing activities was about the same compared to 1997. In 1998, we issued more long-term debt and common stock, and had contributions from minority interests of approximately $86 million related to the acquisition of a distribution company in Panama. This was offset by the repayment of short- term borrowings that matured, sinking fund requirements, and early redemption of higher cost securities. Security Ratings - ---------------- Independent credit-rating agencies rate Constellation Energy and BGE's fixed- income securities. The ratings indicate the agencies' assessment of each company's ability to pay interest, distributions, dividends, and principal on these securities. These ratings affect how much it will cost each company to sell these securities. The better the rating, the lower the cost of the securities to each company when they sell them. Constellation Energy and BGE's securities ratings at the date of this report are: Standard Moody's Duff & Phelps' & Poors Investors Credit Rating Group Service Rating Co. - --------------------------------------------------------------------- Constellation Energy - -------------------- Unsecured Debt A- A3 A BGE - --- Mortgage Bonds AA- A1 AA- Unsecured Debts A A2 A+ Trust Originated Preferred Securities and Preference Stock A- "a2" A 21 Capital Resources - ----------------- Our business requires a great deal of capital. Our actual consolidated capital requirements for the years 1997 through 1999, along with estimated annual amounts for the years 2000 through 2002, are shown in the table below. For the year ended December 31, 1999, the ratio of earnings to fixed charges for Constellation Energy was 2.87. The ratio of earnings to fixed charges for BGE was 3.45 and the ratio of earnings to combined fixed charges and preferred and preference dividend requirements for BGE was 3.14. Investment requirements for 2000 through 2002 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 below because of a number of factors including: . regulation, legislation, and competition, . BGE load requirements, . environmental protection standards, . the type and number of projects selected for development, . the effect of market conditions on those projects, . the cost and availability of capital, and . the availability of cash from operations. Our estimates are also subject to additional factors. Please see the "Forward Looking Statements" section. No earlier than July 1, 2000, and upon receipt of all regulatory approvals, all of BGE's generation assets will be transferred to nonregulated subsidiaries of Constellation Energy. The discussion and table for capital requirements below include these generation assets as part of the utility business.
1997 1998 1999 2000 2001 2002 - -------------------------------------------------------------------------------------------------------------------------------- (In millions) Utility Business Capital Requirements: - ------------------------------------- Construction expenditures (excluding AFC) Electric $ 238 $ 239 $ 283 $ 329 $ 332 $ 312 Gas 89 55 59 63 61 61 Common 38 35 34 25 23 23 - -------------------------------------------------------------------------------------------------------------------------------- Total construction expenditures 365 329 376 417 416 396 AFC 8 10 10 4 4 4 Nuclear fuel (uranium purchases and processing charges) 44 50 49 50 48 48 Deferred conservation expenditures 27 16 1 - - - Retirement of long-term debt and redemption of preference stock 243 222 342 401 281 151 - -------------------------------------------------------------------------------------------------------------------------------- Total utility business capital requirements 687 627 778 872 749 599 - -------------------------------------------------------------------------------------------------------------------------------- Diversified Business Capital Requirements: - ----------------------------------------- Investment requirements 156 325 278 764 1,001 755 Retirement of long-term debt 188 232 189 284 367 2 - -------------------------------------------------------------------------------------------------------------------------------- Total diversified business capital requirements 344 557 467 1,048 1,368 757 - -------------------------------------------------------------------------------------------------------------------------------- Total capital requirements $1,031 $1,184 $1,245 $1,920 $2,117 $1,356 ================================================================================================================================
Capital Requirements of Our Utility Business - -------------------------------------------- Our estimates of future electric construction expenditures do not include costs to build more generating units to meet load requirements for BGE customers. Electric construction expenditures include improvements to generating plants and to our transmission and distribution facilities, and costs for replacing the steam generators and renewing the operating licenses at Calvert Cliffs. The operating licenses expire in 2014 for Unit 1 and in 2016 for Unit 2. If we do not replace the steam generators, we may not be able to operate the Calvert Cliffs units beyond 2014 and 2016. 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. We discuss the license extension process further in the "Current Issues" section. We estimate these Calvert Cliffs costs to be: . $40 million in 2000, . $66 million in 2001, . $88 million in 2002, and . $60 million in 2003. 22 Additionally, our estimates of future electric construction expenditures include the costs of complying with Environmental Protection Agency (EPA) and State of Maryland nitrogen oxides emissions (NOx) reduction regulations as follows: . $63 million in 2000, . $52 million in 2001, and . $4 million in 2002. We discuss the NOx regulations and timing of expenses further in Note 10. Our utility operations provided about 99% in 1999, 108% in 1998, and 105% in 1997 of the cash needed to meet its capital requirements, excluding cash needed to retire debt and redeem preference stock. During the three years from 2000 through 2002, we expect our existing utility business to provide about 115% of the cash needed to meet the capital requirements for these operations, excluding cash needed to retire debt. The table for capital requirements includes the requirements for BGE fossil and nuclear generation under "Utility Business Capital Requirements-Electric" through 2002 even though these assets are to be transferred to nonregulated subsidiaries on or about July 1, 2000. We will continue to have cash requirements for: . working capital needs including the payments of interest, distributions, and dividends, . capital expenditures, and . the retirement of debt and redemption of preference stock. When BGE cannot meet utility capital requirements internally, BGE sells debt and preference stock. BGE also sells securities when market conditions permit it to refinance existing debt or preference stock at a lower cost. The amount of cash BGE needs and market conditions determine when and how much BGE sells. Future funding for capital expenditures, the retirement of debt, and payments of interest and dividends is expected from internally generated funds, commercial paper issuances, available capacity under credit facilities, and/or the issuance of long-term debt, trust securities, or preference stock. At December 31, 1999, the Federal Energy Regulatory Commission has authorized BGE to issue up to $700 million of short-term borrowings, including commercial paper. In addition, BGE maintains $123 million in annual committed bank lines of credit and has $60 million in bank revolving credit agreements to support the commercial paper program as discussed in Note 7. In addition, BGE has access to interim lines of credit as required from time to time to support its outstanding commercial paper. Capital Requirements of Our Diversified Businesses - -------------------------------------------------- Our energy services businesses will require additional funding for: . growing its power marketing business, . developing and acquiring power projects, and . constructing cooling system projects. Our energy services businesses' investment requirements include the planned construction of 800 megawatts of peaking capacity in the Mid-Atlantic/Mid-West region by the summer of 2001 and an additional 4,300 megawatts of peaking and combined cycle production facilities scheduled for completion in 2002 and beyond. Our investment requirements also include our energy services businesses' commitment to contribute up to an additional $121 million in equity to Orion. To date, our energy services businesses have funded $104 million in equity to Orion. Our energy services businesses have met their capital requirements in the past through borrowing, cash from their operations, and from time to time equity contributions from BGE. Future funding for the expansion of our energy services businesses is expected from internally generated funds, commercial paper issuances and long-term debt financing by Constellation Energy, and from time to time equity contributions from Constellation Energy. BGE Home Products & Services may also meet capital requirements through sales of receivables. At December 31, 1999, Constellation Energy has a commercial paper program where it can issue up to $500 million in short-term notes to fund its diversified businesses. To support its commercial paper program, Constellation Energy maintains $35 million in annual committed bank lines of credit and has a $135 million revolving credit agreement, under which it can also issue letters of credit. In addition, Constellation Energy has access to interim lines of credit as required from time to time to support its outstanding commercial paper. ComfortLink has a revolving credit agreement totaling $50 million to provide liquidity for short-term financial needs. If we can get a reasonable value for our real estate projects, additional cash may be obtained by selling them. Our ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. We discuss the real estate business and market in the "Other Diversified Businesses" section. We discuss our short-term borrowings in Note 7 and long-term debt in Note 8. 23 Market Risk - ----------- We are exposed to market risk, including changes in interest rates, certain commodity prices, equity prices, and foreign currency. To manage our market risk, we may enter into various derivative instruments including swaps, forward contracts, futures contracts, and options. Effective July 1, 2000, we will be subject to additional market risk associated with the purchase and sale of energy as discussed in the "Current Issues" section. In this section, we discuss our current market risk and the related use of derivative instruments. Interest Rate Risk - ------------------ We are exposed to changes in interest rates as a result of financing through our issuance of variable-rate and fixed-rate debt. The following table provides information about our obligations that are sensitive to interest rate changes: Principal Payments and Interests Rate Detail by Contractual Maturity Date - -------------------------------------------------------------------------
Fair value at 2000 2001 2002 2003 2004 Thereafter Total Dec 31, 1999 - -------------------------------------------------------------------------------------------------------------------------------- (In millions) Long-term debt - -------------- Variable-rate debt $201.9 $166.0 $ 0.9 $ 7.8 $ 5.4 $ 272.8 $ 654.8 $ 654.8 Average interest rate 6.68% 6.39% 8.32% 7.42% 7.41% 4.80% 5.84% Fixed-rate debt $484.4 $482.8 $154.6 $289.4 $154.6 $1,173.7 $2,739.5 $2,637.3 Average interest rate 7.16% 7.08% 7.31% 6.52% 5.78% 6.83% 6.87%
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 rate incentive mechanism and our off-system gas sales program. We discuss this further in Note 1. At December 31, 1999 and 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 power marketing activities on a portfolio basis, subject to established trading and risk management policies. Commodity price risk arises from the potential for changes in the value of energy commodities and related derivatives due to: changes in commodity prices, volatility of commodity prices, and fluctuations in interest rates. A number of factors associated with the structure and operation of the electricity market significantly influence the level and volatility of prices for electricity and related derivative products. These factors include: . seasonal changes in the demand for electricity, . hourly fluctuations in demand due to weather conditions, . available generation resources, . transmission availability and reliability within and between regions, and . 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: . weather conditions, . market liquidity, . capability and reliability of the physical electricity system, and . the nature and extent of electricity deregulation. Constellation Power Source uses various methods, including a value at risk model, to measure its exposure to market risk. Value at risk is a statistical model that attempts to predict risk of loss based on historical market price and volatility data. Constellation Power Source calculates value at risk using a variance/covariance technique that models option positions using a linear approximation of their value. Additionally, Constellation Power Source estimates variances and correlation using historical market movements over the most recent rolling three-month period. 24 The value at risk amount represents the potential loss in the fair value of assets and liabilities from trading activities over a one-day holding period with a 99.6% confidence level. Using this confidence level, Constellation Power Source would expect a one-day change in fair value greater than or equal to the daily value at risk at least once per year. Constellation Power Source's value at risk was $7.2 million as of December 31, 1999 compared to $6.0 million as of December 31, 1998. The average, high, and low value at risk for the year ended December 31, 1999 was $4.8 million, $7.2 million and $1.8 million, respectively. Constellation Power Source's calculation includes all assets and liabilities from its power marketing and trading activities, including energy commodities and derivatives that do not require cash settlements. We believe that this represents a more complete calculation of our value at risk. Due to the inherent limitations of statistical measures such as value at risk, the relative immaturity of the competitive market for electricity and related derivatives, and the seasonality of changes in market prices, the value at risk calculation may not reflect the full extent of our commodity price risk exposure. Additionally, actual changes in the value of options may differ from the value at risk calculated using a linear approximation inherent in our calculation method. As a result, actual changes in the fair value of assets and liabilities from power marketing and trading activities could differ from the calculated value at risk and such changes could have a material impact on our financial results. Please refer to the "Forward Looking Statements" section below. We discuss Constellation Power Source's business in the "Power Marketing" section and in Note 1. The commodity price risk for our remaining energy services businesses was not material at December 31, 1999 and 1998. 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 NRC to maintain a trust to fund the costs of decommissioning Calvert Cliffs. At December 31, 1999 and 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 $254.1 million invested in 10 international power generation and distribution projects as of December 31, 1999. 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, 1999 and 1998, foreign currency risk was not material. We discuss our international projects in the "Power Projects" section. - -------------------------------------------------------------------------------- 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: . general economic, business, and regulatory conditions, . energy supply and demand, . competition, . federal and state regulations, . availability, terms, and use of capital, . nuclear and environmental issues, . weather, . implications of the Restructuring Order issued by the Maryland PSC, . commodity price risk, . operating our currently regulated generating assets in a deregulated market beginning July 1, 2000 without the benefit of a fuel rate adjustment clause, . loss of revenues due to customers choosing alternative suppliers, . higher volatility of earnings and cash flows, and . increased financial requirements of our nonregulated subsidiaries. Given these uncertainties, you should not place undue reliance on these forward looking statements. Please see the other sections of this report and our other periodic reports filed with the SEC for more information on these factors. These forward looking statements represent our estimates and assumptions only as of the date of this report. 25 Report of Management - -------------------- The management of the Companies is responsible for the information and representations in the Companies' financial statements. The Companies prepare the financial statements in accordance with generally accepted accounting principles based upon available facts and circumstances and management's best estimates and judgments of known conditions. The Companies maintain accounting systems and related systems of internal controls designed to provide reasonable assurance that the financial records are accurate and that the Companies' assets are protected. The Companies' staff of internal auditors, which reports directly to the Chairman of the Board, conducts periodic reviews to maintain the effectiveness of internal control procedures. PricewaterhouseCoopers LLP, independent accountants, audit the financial statements and express their opinion on them. They perform their audit in accordance with generally accepted auditing standards. The Audit Committee of the Board of Directors, which consists of four outside Directors, meets periodically with management, internal auditors, and PricewaterhouseCoopers LLP to review the activities of each in discharging their responsibilities. The internal audit staff and PricewaterhouseCoopers LLP have free access to the Audit Committee. /s/ Christian H. Poindexter /s/ David A. Brune - --------------------------- ------------------ Christian H. Poindexter David A. Brune Chairman of the Board Chief Financial Officer and Chief Executive Officer Report of Independent Accountants - --------------------------------- To the Shareholders of Constellation Energy Group, Inc. and Baltimore Gas and Electric Company In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, cash flows, common shareholders' equity, capitalization and income taxes present fairly, in all material respects, the financial position of Constellation Energy Group, Inc. and Subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, and the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income and cash flows present fairly, in all material respects, the financial position of Baltimore Gas and Electric Company and Subsidiaries at December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Companies' management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. We have also previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheets and statement of capitalization of Baltimore Gas and Electric Company as of December 31, 1997, 1996 and 1995, and the related consolidated statements of income, comprehensive income, cash flows, common shareholders' equity and income taxes for the years ended December 31, 1996 and 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 of Constellation Energy Group, Inc. included in the Selected Financial Data for each of the five years in the period ended December 31, 1999, and the information set forth in the Summary of Operations and Summary of Financial Condition of Baltimore Gas and Electric Company included in the Selected Financial Data for each of the five years in the period ended December 31, 1999, is fairly stated, in all material respects, in relation to the consolidated financial statements from which it has been derived. /s/ PricewaterhouseCoopers LLP - ------------------------------ PricewaterhouseCoopers LLP Baltimore, Maryland January 19, 2000 26 Consolidated Statements of Income - Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 1999 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (In millions, except per share amounts) Revenues Electric $2,258.8 $2,219.2 $2,191.7 Gas 476.5 449.4 521.6 Diversified businesses 1,050.9 689.5 594.3 - ------------------------------------------------------------------------------------------------------------------- Total revenues 3,786.2 3,358.1 3,307.6 Operating Expenses Electric fuel and purchased energy 467.7 505.7 519.7 Gas purchased for resale 230.6 208.6 292.1 Operations 546.0 554.1 518.3 Maintenance 186.2 177.5 178.5 Diversified businesses--selling, general, and administrative 918.7 574.6 515.7 Depreciation and amortization 449.8 377.1 342.9 Taxes other than income taxes 227.3 219.4 216.8 - ------------------------------------------------------------------------------------------------------------------- Total operating expenses 3,026.3 2,617.0 2,584.0 - ------------------------------------------------------------------------------------------------------------------- Income from Operations 759.9 741.1 723.6 Other Income (Expense) Write-off of merger costs (see Note 2) - - (57.9) Other 7.9 5.7 5.1 - ------------------------------------------------------------------------------------------------------------------- Total other income (expense) 7.9 5.7 (52.8) - ------------------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 767.8 746.8 670.8 Fixed Charges Interest expense (net) 241.5 240.9 230.0 BGE preference stock dividends 13.5 21.8 28.7 - ------------------------------------------------------------------------------------------------------------------- Total fixed charges 255.0 262.7 258.7 - ------------------------------------------------------------------------------------------------------------------- Income Before Income Taxes 512.8 484.1 412.1 Income Taxes 186.4 178.2 158.0 - ------------------------------------------------------------------------------------------------------------------- Income Before Extraordinary Item 326.4 305.9 254.1 Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 4) (66.3) - - - ------------------------------------------------------------------------------------------------------------------- Net Income $ 260.1 $ 305.9 $ 254.1 =================================================================================================================== Earnings Applicable to Common Stock $ 260.1 $ 305.9 $ 254.1 =================================================================================================================== Average Shares of Common Stock Outstanding 149.6 148.5 147.7 Earnings Per Common Share and Earnings Per Common Share --Assuming Dilution Before Extraordinary Item $ 2.18 $ 2.06 $ 1.72 Extraordinary Loss (.44) - - - ------------------------------------------------------------------------------------------------------------------- Earnings Per Common Share and Earnings Per Common Share --Assuming Dilution $ 1.74 $ 2.06 $ 1.72 =================================================================================================================== Consolidated Statements of Comprehensive Income - Constellation Energy Group, Inc. and Subsidiaries Year Ended December 31, 1999 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (In millions) Net Income $ 260.1 $ 305.9 $ 254.1 Other comprehensive income/(loss), net of taxes (6.2) 1.2 (0.8) - ------------------------------------------------------------------------------------------------------------------- Comprehensive Income $ 253.9 $ 307.1 $ 253.3 ===================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 27 Consolidated Balance Sheets - Constellation Energy Group, Inc. and Subsidiaries At December 31, 1999 1998 - ------------------------------------------------------------------------------- (In millions) Assets Current Assets Cash and cash equivalents $ 92.7 $ 173.7 Accounts receivable (net of allowance for uncollectibles of $34.8 and $35.4 respectively) 578.5 422.7 Trading securities 136.5 119.7 Assets from energy trading activities 312.1 133.0 Fuel stocks 94.9 85.4 Materials and supplies 149.1 145.1 Prepaid taxes other than income taxes 72.4 68.8 Other 54.0 21.4 - ------------------------------------------------------------------------------- Total current assets 1,490.2 1,169.8 - ------------------------------------------------------------------------------- Investments and Other Assets Real estate projects and investments 310.1 353.9 Power projects 785.4 743.1 Financial investments 145.4 198.0 Nuclear decommissioning trust fund 217.9 181.4 Net pension asset 99.5 108.0 Other 422.9 243.3 - ------------------------------------------------------------------------------- Total investments and other assets 1,981.2 1,827.7 - ------------------------------------------------------------------------------- Utility Plant Plant in service Electric 7,088.6 6,890.3 Gas 962.0 921.3 Common 569.5 552.8 - ------------------------------------------------------------------------------- Total plant in service 8,620.1 8,364.4 Accumulated depreciation (3,466.1) (3,087.5) - ------------------------------------------------------------------------------- Net plant in service 5,154.0 5,276.9 Construction work in progress 222.3 223.0 Nuclear fuel (net of amortization) 133.8 132.5 Plant held for future use 13.0 24.3 - ------------------------------------------------------------------------------- Net utility plant 5,523.1 5,656.7 - ------------------------------------------------------------------------------- Deferred Charges Regulatory assets (net) 637.4 565.7 Other 51.9 55.1 - ------------------------------------------------------------------------------- Total deferred charges 689.3 620.8 - ------------------------------------------------------------------------------- Total Assets $ 9,683.8 $ 9,275.0 =============================================================================== See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 28 Consolidated Balance Sheets - Constellation Energy Group Inc. and Subsidiaries
At December 31, 1999 1998 - --------------------------------------------------------------------------------------------------------------- (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 371.5 $ - Current portions of long-term debt and preference stock 808.3 541.7 Accounts payable 365.1 270.5 Customer deposits 40.6 35.5 Liabilities from energy trading activities 163.8 99.0 Dividends declared 66.1 66.1 Accrued taxes 19.2 6.5 Accrued interest 55.3 58.6 Accrued vacation costs 35.3 34.7 Other 78.2 45.3 - --------------------------------------------------------------------------------------------------------------- Total current liabilities 2,003.4 1,157.9 - --------------------------------------------------------------------------------------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 1,288.8 1,309.1 Postretirement and postemployment benefits 269.8 217.0 Deferred investment tax credits 109.6 118.0 Decommissioning of federal uranium enrichment facilities 27.2 30.8 Other 226.6 142.6 - --------------------------------------------------------------------------------------------------------------- Total deferred credits and other liabilities 1,922.0 1,817.5 - --------------------------------------------------------------------------------------------------------------- Capitalization Long-term debt 2,575.4 3,128.1 BGE preference stock not subject to mandatory redemption 190.0 190.0 Common shareholders' equity 2,993.0 2,981.5 - --------------------------------------------------------------------------------------------------------------- Total capitalization 5,758.4 6,299.6 - --------------------------------------------------------------------------------------------------------------- Commitments, Guarantees, and Contingencies (see Note 10) Total Liabilities and Capitalization $ 9,683.8 $ 9,275.0 ===============================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 29 Consolidated Statements of Cash Flows - Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 1999 1998 1997 - ---------------------------------------------------------------------------------------------------------------------------------- (In millions) Cash Flows From Operating Activities Net income $ 260.1 $ 305.9 $ 254.1 Adjustments to reconcile to net cash provided by operating activities Extraordinary loss 66.3 - - Depreciation and amortization 505.9 429.4 396.8 Deferred income taxes 13.0 17.5 7.4 Investment tax credit adjustments (8.6) (8.8) (7.5) Deferred fuel costs (61.1) (8.3) 18.3 Accrued pension and postemployment benefits 36.1 41.6 (18.0) Write-off of merger costs - - 57.9 Write-downs of real estate investments 8.3 23.7 70.8 Write-down of financial investment 26.2 - - Write-downs of power projects 28.5 - - Equity in earnings of affiliates and joint ventures (net) (7.6) (54.5) (42.5) Changes in assets from energy trading activities (179.1) (123.6) (9.4) Changes in liabilities from energy trading activities 64.8 90.4 8.6 Changes in other current assets (216.4) 18.3 (54.7) Changes in other current liabilities 121.0 77.0 42.6 Other 21.6 (8.8) (28.1) - ---------------------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 679.0 799.8 696.3 - ---------------------------------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Utility construction and other capital expenditures (436.2) (406.1) (443.9) Contributions to nuclear decommissioning trust fund (17.6) (17.6) (17.6) Merger costs - - (20.9) Purchases of marketable equity securities (27.3) (33.3) (23.0) Sales of marketable equity securities 34.9 32.8 46.5 Other financial investments 13.7 14.6 (0.4) Real estate projects and investments 49.3 21.5 24.2 Power projects (171.1) (252.5) (44.3) Other (60.8) (70.7) (41.4) - ---------------------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (615.1) (711.3) (520.8) - ---------------------------------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 2,801.9 1,962.2 2,719.0 Long-term debt 302.8 831.3 622.0 Common stock 9.6 51.8 - Repayment of short-term borrowings (2,430.4) (2,278.3) (2,736.1) Reacquisition of long-term debt (584.4) (355.2) (343.3) Redemption of preference stock (7.0) (127.9) (104.5) Common stock dividends paid (251.1) (246.0) (239.2) Other 13.7 84.7 2.5 - ---------------------------------------------------------------------------------------------------------------------------------- Net cash used in financing activities (144.9) (77.4) (79.6) - ---------------------------------------------------------------------------------------------------------------------------------- Net (Decrease) Increase in Cash and Cash Equivalents (81.0) 11.1 95.9 Cash and Cash Equivalents at Beginning of Year 173.7 162.6 66.7 - ---------------------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 92.7 $ 173.7 $ 162.6 ================================================================================================================================== Other Cash Flow Information - --------------------------- Cash paid during the year for: Interest (net of amounts capitalized) $ 245.3 $ 236.7 $ 224.2 Income taxes $ 165.6 $ 164.3 $ 171.2
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. 30 Consolidated Statements of Common Shareholders' Equity - Constellation Energy Group Inc. and Subsidiaries
Accumulated Other Common Stock Retained Comprehensive Total Years Ended December 31, 1999, 1998 and 1997 Shares Amount Earnings (Loss) Income Amount - --------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions, number of shares in thousands) Balance at December 31, 1996 147,667 $ 1,429.9 $ 1,419.1 $ 5.7 $2,854.7 Net income 254.1 254.1 Common stock dividends declared ($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 305.9 305.9 Common stock dividend declared ($1.67 per share) (248.1) (248.1) Common stock issued 1,579 51.8 51.8 Other 0.3 0.3 Net unrealized gain on securities 1.8 1.8 Deferred taxes on net unrealized gain on securities (0.6) (0.6) - --------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1998 149,246 1,485.1 1,490.3 6.1 2,981.5 Net income 260.1 260.1 Common stock dividend declared ($1.68 per share) (251.3) (251.3) Common stock issued 310 9.6 9.6 Other (0.7) (0.7) Net unrealized loss on securities (9.6) (9.6) Deferred taxes on net unrealized loss on securities 3.4 3.4 - --------------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 149,556 $ 1,494.0 $ 1,499.1 $ (0.1) $2,993.0 ===========================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 31 Consolidated Statements of Capitalization - Constellation Energy Group, Inc. and Subsidiaries
At December 31, 1999 1998 - ---------------------------------------------------------------------------------------------------------------------- (In millions) Long-Term Debt First Refunding Mortgage Bonds of BGE Floating rate series, due April 15, 1999 $ - $ 125.0 8.40% Series, due October 15, 1999 - 91.1 5 1/2% Series, due July 15, 2000 124.3 125.0 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 8.5 9.1 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 109.9 125.0 7 1/2% Series, due April 15, 2023 84.1 84.1 - ---------------------------------------------------------------------------------------------------------------------- Total First Refunding Mortgage Bonds of BGE 1,321.7 1,554.2 - ---------------------------------------------------------------------------------------------------------------------- Other long-term debt of BGE Medium-term notes, Series B 60.0 60.0 Medium-term notes, Series C 101.0 116.0 Medium-term notes, Series D 128.0 215.0 Medium-term notes, Series E 200.0 200.0 Medium-term notes, Series G 200.0 140.0 Medium-term notes, Series H 177.0 - 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 1,135.8 1,000.8 - ---------------------------------------------------------------------------------------------------------------------- BGE obligated mandatorily redeemable trust preferred securities of subsidiary trust holding solely 7.16% deferrable interest subordinated debentures due June 30, 2038 250.0 250.0 - ---------------------------------------------------------------------------------------------------------------------- Long-term debt of diversified businesses Loans under revolving credit agreements 33.0 74.0 Mortgage and construction loans 7.90% mortgage note, due September 12, 2000 8.0 8.3 8.00% mortgage note, due July 31, 2001 0.1 0.1 8.00% mortgage note, due October 30, 2003 1.9 1.8 Variable rate mortgage notes and construction loans, due through 2004 112.0 149.5 4.25% mortgage note, due March 15, 2009 4.6 5.1 9.65% mortgage note, due February 1, 2028 9.6 9.6 8.00% mortgage note, due November 1, 2033 6.6 5.8 Unsecured notes 511.0 616.0 - ---------------------------------------------------------------------------------------------------------------------- Total long-term debt of diversified businesses 686.8 870.2 - ---------------------------------------------------------------------------------------------------------------------- Unamortized discount and premium (10.6) (12.4) Current portion of long-term debt (808.3) (534.7) - ---------------------------------------------------------------------------------------------------------------------- Total long-term debt $ 2,575.4 $ 3,128.1 - ----------------------------------------------------------------------------------------------------------------------
continued on next page See Notes to Consolidated Financial Statements. 32 Consolidated Statements of Capitalization - Constellation Energy Group, Inc. and Subsidiaries
At December 31, 1999 1998 - ----------------------------------------------------------------------------------------------------------------------------- (In millions) BGE Preference Stock Cumulative, $100 par value, 6,500,000 shares authorized Redeemable preference stock 7.85%, 1991 Series $ - $ 7.0 Current portion of redeemable preference stock - (7.0) - ----------------------------------------------------------------------------------------------------------------------------- Total redeemable preference stock - - - ----------------------------------------------------------------------------------------------------------------------------- Preference stock not subject to mandatory redemption 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40.0 40.0 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50.0 50.0 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40.0 40.0 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60.0 60.0 - ----------------------------------------------------------------------------------------------------------------------------- Total preference stock not subject to mandatory redemption 190.0 190.0 - ----------------------------------------------------------------------------------------------------------------------------- Common Shareholders' Equity Common stock without par value, 250,000,000 shares authorized; 149,556,416 and 149,245,641 shares issued and outstanding at December 31, 1999 and 1998, respectively. (At December 31, 1999 166,893 shares were reserved for the Employee Savings Plan and 12,061,756 shares were reserved for the Shareholder Investment Plan.) 1,494.0 1,485.1 Retained earnings 1,499.1 1,490.3 Accumulated other comprehensive (loss) income (0.1) 6.1 - ----------------------------------------------------------------------------------------------------------------------------- Total common shareholders' equity 2,993.0 2,981.5 - ----------------------------------------------------------------------------------------------------------------------------- Total Capitalization $5,758.4 $6,299.6 =============================================================================================================================
See Notes to Consolidated Financial Statements. 33 Consolidated Statements of Income Taxes - Constellation Energy Group, Inc. and Subsidiaries
Year Ended December 31, 1999 1998 1997 - ---------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions) Income Taxes Current $ 182.0 $ 169.5 $158.1 - ---------------------------------------------------------------------------------------------------------------------------- Deferred Change in tax effect of temporary differences 9.6 14.2 (1.0) Change in income taxes recoverable through future rates - 3.9 8.0 Deferred taxes credited (charged) to shareholders' equity 3.4 (0.6) 0.4 - ---------------------------------------------------------------------------------------------------------------------------- Deferred taxes charged to expense 13.0 17.5 7.4 Investment tax credit adjustments (8.6) (8.8) (7.5) - ---------------------------------------------------------------------------------------------------------------------------- Income taxes per Consolidated Statements of Income $ 186.4 $ 178.2 $158.0 ============================================================================================================================ Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes (excluding BGE preference stock dividends) $ 526.3 $ 505.9 $440.8 Statutory federal income tax rate 35% 35% 35% - ---------------------------------------------------------------------------------------------------------------------------- Income taxes computed at statutory federal rate 184.2 177.1 154.3 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 15.3 13.6 13.9 Allowance for equity funds used during construction (2.2) (2.2) (1.9) Amortization of deferred investment tax credits (8.6) (8.8) (7.5) Tax credits flowed through to income (3.2) (0.3) (0.5) Amortization of deferred tax rate differential on regulated activities (3.0) (2.3) (2.3) State income taxes 8.9 9.8 6.2 Other (5.0) (8.7) (4.2) - ---------------------------------------------------------------------------------------------------------------------------- Total income taxes $ 186.4 $ 178.2 $158.0 ============================================================================================================================ Effective federal income tax rate 35.4% 35.2% 35.8% At December 31, 1999 1998 - ------------------------------------------------------------------------------------------------------------------- (Dollar amounts in millions) Deferred Income Taxes Deferred tax liabilities Accelerated depreciation $ 962.7 $1,009.9 Allowance for funds used during construction 202.3 204.5 Income taxes recoverable through future rates 35.7 88.4 Deferred termination and postemployment costs 14.7 32.3 Deferred fuel costs 25.8 4.5 Leveraged leases 19.9 22.6 Percentage repair allowance 35.0 36.8 Conservation expenditures 4.7 18.9 Energy trading activities 71.4 33.4 Deferred electric generation-related regulatory assets 100.3 - Other 187.9 182.6 - ------------------------------------------------------------------------------------------------------------------- Total deferred tax liabilities 1,660.4 1,633.9 - ------------------------------------------------------------------------------------------------------------------- Deferred tax assets Accrued pension and postemployment benefit costs 63.6 54.3 Deferred investment tax credits 38.3 41.3 Capitalized interest and overhead 48.3 46.6 Contributions in aid of construction 49.1 45.6 Nuclear decommissioning liability 25.4 22.8 Energy trading activities 15.1 20.3 Other 131.8 93.9 - ------------------------------------------------------------------------------------------------------------------- Total deferred tax assets 371.6 324.8 - ------------------------------------------------------------------------------------------------------------------- Deferred tax liability, net $1,288.8 $1,309.1 ===================================================================================================================
See Notes to Consolidated Financial Statements. Certain prior year amounts have been reclassified to confirm with the current year's presentation. 34 Consolidated Statements of Income - Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, 1999 1998 1997 - ------------------------------------------------------------------------------------------------------- (In millions, except per share amounts) Revenues Electric $2,259.5 $2,219.2 $ 2,191.7 Gas 485.3 449.4 521.6 Diversified businesses 283.5 689.5 594.3 - ------------------------------------------------------------------------------------------------------- Total revenues 3,028.3 3,358.1 3,307.6 Operating Expenses Electric fuel and purchased energy 486.8 505.7 519.7 Gas purchased for resale 233.7 208.6 292.1 Operations 543.9 554.1 518.3 Maintenance 184.9 177.5 178.5 Diversified businesses--selling, general, and administrative 222.1 574.6 515.7 Depreciation and amortization 427.9 377.1 342.9 Taxes other than income taxes 224.7 219.4 216.8 - ------------------------------------------------------------------------------------------------------- Total operating expenses 2,324.0 2,617.0 2,584.0 - ------------------------------------------------------------------------------------------------------- Income from Operations 704.3 741.1 723.6 Other Income (Expense) Write-off of merger costs (see Note 2) - - (57.9) Allowance for equity funds used during construction 6.2 6.3 5.3 Equity in earnings of Safe Harbor Water Power Corporation 5.1 5.0 5.0 Net other expense (2.9) (5.6) (5.2) - ------------------------------------------------------------------------------------------------------- Total other income (expense) 8.4 5.7 (52.8) - ------------------------------------------------------------------------------------------------------- Income Before Fixed Charges and Income Taxes 712.7 746.8 670.8 Fixed Charges Interest expense (net) 210.1 247.9 241.2 Capitalized interest (0.4) (3.6) (8.4) Allowance for borrowed funds used during construction (3.8) (3.4) (2.8) - ------------------------------------------------------------------------------------------------------- Total fixed charges 205.9 240.9 230.0 - ------------------------------------------------------------------------------------------------------- Income Before Income Taxes 506.8 505.9 440.8 Income Taxes Current 192.1 169.5 158.1 Deferred (5.2) 17.5 7.4 Investment tax credit adjustments (8.5) (8.8) (7.5) - ------------------------------------------------------------------------------------------------------- Total income taxes 178.4 178.2 158.0 - ------------------------------------------------------------------------------------------------------- Income Before Extraordinary Item 328.4 327.7 282.8 Extraordinary Loss, Net of Income Taxes of $30.4 (see Note 4) (66.3) - - - ------------------------------------------------------------------------------------------------------- Net Income 262.1 327.7 282.8 Preference Stock Dividends 13.5 21.8 28.7 - ------------------------------------------------------------------------------------------------------- Earnings Applicable to Common Stock $ 248.6 $ 305.9 $ 254.1 =======================================================================================================
Consolidated Statements of Comprehensive Income - Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, 1999 1998 1997 - ------------------------------------------------------------------------------------------------------- (In millions, except per share amounts) Net Income $ 262.1 $ 327.7 $ 282.8 Other comprehensive income/(loss), net of taxes (3.4) 1.2 (0.8) - ------------------------------------------------------------------------------------------------------- Comprehensive Income $ 258.7 $ 328.9 $ 282.0 =======================================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 35
Consolidated Balance Sheets - Baltimore Gas and Electric Company and Subsidiaries At December 31, 1999 1998 - ------------------------------------------------------------------------------------------ (In millions) Assets Current Assets Cash and cash equivalents $ 23.5 $ 173.7 Accounts receivable (net of allowance for uncollectibles of $13.0 and $35.4 respectively) 316.1 422.7 Trading securities - 119.7 Assets from energy trading activities - 133.0 Fuel stocks 94.9 85.4 Materials and supplies 139.1 145.1 Prepaid taxes other than income taxes 72.4 68.8 Other 9.0 21.4 - ------------------------------------------------------------------------------------------ Total current assets 655.0 1,169.8 - ------------------------------------------------------------------------------------------ Investments and Other Assets Real estate projects and investments - 353.9 Power projects - 743.1 Financial investments - 198.0 Nuclear decommissioning trust fund 217.9 181.4 Net pension asset 99.8 108.0 Safe Harbor Water Power Corporation 34.5 34.4 Senior living facilities - 93.5 Other 61.6 115.4 - ------------------------------------------------------------------------------------------ Total investments and other assets 413.8 1,827.7 - ------------------------------------------------------------------------------------------ Utility Plant Plant in service Electric 7,088.6 6,890.3 Gas 962.0 921.3 Common 569.5 552.8 - ------------------------------------------------------------------------------------------ Total plant in service 8,620.1 8,364.4 Accumulated depreciation (3,466.1) (3,087.5) - ------------------------------------------------------------------------------------------ Net plant in service 5,154.0 5,276.9 Construction work in progress 222.3 223.0 Nuclear fuel (net of amortization) 133.8 132.5 Plant held for future use 13.0 24.3 - ------------------------------------------------------------------------------------------ Net utility plant 5,523.1 5,656.7 - ------------------------------------------------------------------------------------------ Deferred Charges Regulatory assets (net) 637.4 565.7 Other 43.3 55.1 - ------------------------------------------------------------------------------------------ Total deferred charges 680.7 620.8 - ------------------------------------------------------------------------------------------ Total Assets $7,272.6 $9,275.0 ==========================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 36
Consolidated Balance Sheets - Baltimore Gas and Electric Company and Subsidiaries At December 31, 1999 1998 - ------------------------------------------------------------------------------------------ (In millions) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 129.0 $ - Current portions of long-term debt and preference stock 523.9 541.7 Accounts payable 222.8 270.5 Customer deposits 40.6 35.5 Liabilities from energy trading activities - 99.0 Dividends declared 3.3 66.1 Accrued taxes 9.2 6.5 Accrued interest 48.2 58.6 Accrued vacation costs 35.7 34.7 Other 65.8 45.3 - ------------------------------------------------------------------------------------------ Total current liabilities 1,078.5 1,157.9 - ------------------------------------------------------------------------------------------ Deferred Credits and Other Liabilities Deferred income taxes 1,032.0 1,309.1 Postretirement and postemployment benefits 231.0 217.0 Deferred investment tax credits 109.6 118.0 Decommissioning of federal uranium enrichment facilities 27.2 30.8 Other 42.9 142.6 - ------------------------------------------------------------------------------------------ Total deferred credits and other liabilities 1,442.7 1,817.5 - ------------------------------------------------------------------------------------------ Long-term Debt First refunding mortgage bonds of BGE 1,321.7 1,554.2 Other long-term debt of BGE 1,135.8 1,000.8 Company obligated mandatorily redeemable trust preferred securities 250.0 250.0 Long-term debt of diversified businesses 33.0 870.2 Unamortized discount and premium (10.6) (12.4) Current portion of long-term debt (523.9) (534.7) - ------------------------------------------------------------------------------------------ Total long-term debt 2,206.0 3,128.1 - ------------------------------------------------------------------------------------------ Redeemable Preference Stock - 7.0 Current portion of redeemable preference stock - (7.0) - ------------------------------------------------------------------------------------------ Total redeemable preference stock - - - ------------------------------------------------------------------------------------------ Preference Stock Not Subject to Mandatory Redemption 190.0 190.0 Common Shareholder's Equity Common stock 1,494.0 1,485.1 Retained earnings 861.4 1,490.3 Accumulated other comprehensive income - 6.1 - ------------------------------------------------------------------------------------------ Total common shareholder's equity 2,355.4 2,981.5 - ------------------------------------------------------------------------------------------ Total capitalization 4,751.4 6,299.6 - ------------------------------------------------------------------------------------------ Commitments, Guarantees, and Contingencies (see Note 10) Total Liabilities and Capitalization $7,272.6 $9,275.0 ==========================================================================================
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. 37 Consolidated Statements of Cash Flows - Baltimore Gas and Electric Company and Subsidiaries
Year Ended December 31, 1999 1998 1997 - ------------------------------------------------------------------------------------------------------------------- (In millions) Cash Flows From Operating Activities Net income $ 262.1 $ 327.7 $ 282.8 Adjustments to reconcile to net cash provided by operating activities Extraordinary loss 66.3 - - Depreciation and amortization 480.4 429.4 396.8 Deferred income taxes (5.2) 17.5 7.4 Investment tax credit adjustments (8.5) (8.8) (7.5) Deferred fuel costs (61.1) (8.3) 18.3 Accrued pension and postemployment benefits 35.5 41.6 (18.0) Write-off of merger costs - - 57.9 Write-downs of real estate investments - 23.7 70.8 Allowance for equity funds used during construction (6.2) (6.3) (5.3) Equity in earnings of affiliates and joint ventures (net) 29.1 (54.5) (42.5) Changes in assets from energy trading activities (133.0) (123.6) (9.4) Changes in liabilities from energy trading activities 99.0 90.4 8.6 Changes in other current assets (15.1) 18.3 (54.7) Changes in other current liabilities 22.7 77.0 42.6 Other 16.7 (3.3) (21.8) - ------------------------------------------------------------------------------------------------------------------- Net cash provided by operating activities 782.7 820.8 726.0 - ------------------------------------------------------------------------------------------------------------------- Cash Flows From Investing Activities Utility construction expenditures (including AFC) (385.9) (339.4) (373.2) Allowance for equity funds used during construction 6.2 6.3 5.3 Nuclear fuel expenditures (49.2) (50.5) (43.6) Deferred conservation expenditures (1.1) (16.2) (27.1) Contributions to nuclear decommissioning trust fund (17.6) (17.6) (17.6) Merger costs - - (20.9) Purchases of marketable equity securities (9.2) (33.3) (23.0) Sales of marketable equity securities 6.0 32.8 46.5 Other financial investments 6.7 14.6 (0.4) Real estate projects and investments 22.0 21.5 24.2 Power projects (17.9) (252.5) (44.3) Other (20.7) (77.0) (46.7) - ------------------------------------------------------------------------------------------------------------------- Net cash used in investing activities (460.7) (711.3) (520.8) - ------------------------------------------------------------------------------------------------------------------- Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings 2,504.1 1,962.2 2,719.0 Long-term debt 257.2 831.3 622.0 Common stock 9.6 51.8 - Repayment of short-term borrowings (2,375.1) (2,278.3) (2,736.1) Reacquisition of long-term debt (466.3) (355.2) (343.3) Redemption of preference stock (7.0) (127.9) (104.5) Common stock dividends paid (251.1) (246.0) (239.2) Preferred and preference stock dividends paid (13.6) (21.0) (29.7) Distribution of cash to Constellation Energy (128.2) - - Other (1.8) 84.7 2.5 - ------------------------------------------------------------------------------------------------------------------- Net cash used in financing activities (472.2) (98.4) (109.3) - ------------------------------------------------------------------------------------------------------------------- Net (Decrease) Increase in Cash and Cash Equivalents (150.2) 11.1 95.9 Cash and Cash Equivalents at Beginning of Year 173.7 162.6 66.7 - ------------------------------------------------------------------------------------------------------------------- Cash and Cash Equivalents at End of Year $ 23.5 $ 173.7 $ 162.6 =================================================================================================================== Other Cash Flow Information - --------------------------- Cash paid during the year for: Interest (net of amounts capitalized) $ 200.2 $ 236.7 $ 224.2 Income taxes $ 178.8 $ 164.3 $ 171.2 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. 38 Notes to Consolidated Financial Statements - ------------------------------------------ Note 1 - ------ Significant Accounting Policies - ------------------------------- Nature of Our Business - ---------------------- On April 30, 1999, Constellation Energy Group, Inc. (Constellation Energy) became the holding company for Baltimore Gas and Electric Company (BGE) and BGE's former subsidiary Constellation Enterprises, Inc. BGE's outstanding common stock automatically became shares of common stock of Constellation Energy. BGE's debt securities, obligated mandatorily redeemable trust preferred securities, and preference stock remain securities of BGE. Constellation Energy's subsidiaries primarily include BGE and a group of energy services businesses mostly focused on power marketing and merchant generation in North America. BGE is an electric and gas public utility company with a service territory that covers the City of Baltimore and all or part of ten counties in Central Maryland. We describe our operating segments in Note 2. References in this report to "we" and "our" are to Constellation Energy and its subsidiaries, collectively. Reference in this report to the "utility business" is to BGE. Consolidation Policy - -------------------- We use three different accounting methods to report our investments in our subsidiaries or other companies: consolidation, the equity method, and the cost method. Consolidation - ------------- We use consolidation when we own a majority of the voting stock of the subsidiary. This means the accounts of our subsidiaries are combined with our accounts. We eliminate intercompany balances and transactions when we consolidate these accounts. This report is a combined report of Constellation Energy and BGE. The consolidated financial statements of Constellation Energy include the accounts of Constellation Energy, BGE and its subsidiaries, Constellation Enterprises, Inc. and its subsidiaries, and Constellation Nuclear Group, LLC and its subsidiaries. The consolidated financial statements of BGE include the accounts of BGE, ComfortLink, and BGE Capital Trust I. As Constellation Enterprises and its subsidiaries were subsidiaries of BGE prior to April 30, 1999, they are included in the consolidated financial statements of BGE through that date. The Equity Method - ----------------- We usually use the equity method to report investments, corporate joint ventures, partnerships, and affiliated companies (including power projects) where we hold a 20% to 50% voting interest. Under the equity method, we report: . our interest in the entity as an investment in our Consolidated Balance Sheets, . 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. BGE reports its 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. This investment is included in "Investments and Other Assets - Other" in our Consolidated Balance Sheets. The Cost Method - --------------- We usually use the cost method if we hold less than a 20% voting interest in an investment. Under the cost method, we report our investment at cost in our Consolidated Balance Sheets. The only time we do not use this method is when we can exercise significant influence over the operations and policies of the company. If we have significant influence, accounting rules require us to use the equity method. Regulation of Utility Business - ------------------------------ The Maryland Public Service Commission (Maryland PSC) provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under 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 5. In 1997, the Financial Accounting Standards Board (FASB) through its Emerging Issues Task Force (EITF) issued EITF 97-4, Deregulation of the Pricing of Electricity -Issues Related to the Application of FASB Statements No. 71 and 101. The EITF concluded that a company should cease to apply SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulated assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery. 39 On November 10, 1999, the Maryland PSC issued a Restructuring Order that we believe provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101, Regulated Enterprises - Accounting for the Discontinuation of FASB Statement No. 71 and EITF No. 97-4 for BGE's electric generation business. BGE's transmission and distribution business continues to meet the requirements of SFAS No. 71 as that business remains regulated. We discuss this further in Note 4. 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: . the fuel we use to generate electricity, . purchases of electricity from others, and . 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 - -------------------------------------------------------------------------- Until July 1, 2000, we will continue to recover our costs of electric fuel under the electric fuel rate clause set by the Maryland PSC. Under the electric fuel rate clause, we charge our electric customers for: . the fuel we use to generate electricity (nuclear fuel, coal, gas, or oil), and . the net cost of purchases and sales of electricity. We 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 currently 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 and the impact of the Restructuring Order on BGE's electric fuel rate clause further in Note 4. We calculate the electric fuel rate using three factors: . the mix of generating plants we used over the last 24 months, . the latest three-month average fuel cost for each generating unit, and . the net cost of purchases and sales of electricity over the last 24 months. Historically, we were able to change the fuel rate only if the calculated rate was more than 5% above or below the rate in effect. The fuel rate was 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. As a result of the Restructuring Order, the fuel rate is frozen at its current level until July 1, 2000, at which time it will be discontinued. We will continue to defer the difference between our actual costs of fuel and energy and what we collect from customers under the fuel rate through June 30, 2000. After that date, earnings will be affected by the changes in the cost of fuel and energy. In addition, any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC. Extended outages at Calvert Cliffs increase fuel costs. Any increase in fuel costs, including extended outages at Calvert Cliffs through June 30, 2000, 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 also report two other items as "Electric fuel and purchased energy" in our Consolidated Statements of Income: . 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 . amortization of deferred costs of decommissioning and decontaminating the Department of Energy's uranium enrichment facilities. We discuss these costs further in Note 5. 40 Natural Gas - ----------- We charge our gas customers for the natural gas they purchase from us using "gas cost adjustment clauses" set by the Maryland PSC. These clauses operate similarly to the electric fuel rate clause described earlier in this Note. However, the Maryland PSC approved a modification of the gas cost adjustment clauses to provide a market based rates incentive mechanism. Under market based rates our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between our actual cost and the market index is shared equally between shareholders and customers. Risk Management - --------------- We 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. Our gas business internal guidelines do not permit the use of swap agreements for any purpose other than to hedge price risk. BGE's off-system gas activities represent trading activities under EITF 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Accordingly, we use mark-to-market accounting to record these transactions. We defer, as unrealized gains or losses, the changes in fair value of the swap agreements under the market based rates incentive mechanism and the customers' portion of off-system gas sales in our Consolidated Balance Sheets. When amounts are paid under the agreements, we report the payments as gas costs in our Consolidated Statements of Income. We report the changes in fair value for the shareholders' portion of off-system gas sales in earnings as a component of gas costs. 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: . commodity positions and derivatives at fair value as "Assets from energy trading activities" or "Liabilities from energy trading activities" in our Consolidated Balance Sheets, and . changes in fair value 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 deferred income tax expense is equal to the changes in the net deferred income tax liability, excluding amounts charged or credited to common shareholders' equity. Our deferred income tax expense is increased or reduced for changes to the "Income taxes recoverable through future rates (net)" regulatory asset (described later in this Note) during the year. Investment Tax Credits - ---------------------- We have deferred the investment tax credit associated with our regulated utility business in our Consolidated Balance Sheets. The investment tax credit is amortized evenly to income over the life of each property. We reduce income tax expense in our Consolidated Statements of Income for the investment tax credit and other tax credits associated with our nonregulated diversified businesses, other than leveraged leases. 41 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 through future rates (net)." We have recorded that portion of the net liability as a regulatory asset in our Consolidated Balance Sheets. We discuss this further in Note 5. State and Local Taxes - --------------------- Through December 31, 1999, we paid 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. As discussed in Note 4, the tax legislation made comprehensive changes to the state and local taxation of electric and gas utilities. Inventory - --------- We report the majority of our fuel stocks and materials and supplies at average cost. Real Estate Projects and Investments - ------------------------------------ In Note 3, we summarize the real estate projects and investments that are in our Consolidated Balance Sheets. The projects and investments consist of: . land under development in the Baltimore-Washington corridor, . a mixed-use planned-unit development, . senior-living facilities, and . an equity interest in Corporate Office Properties Trust, a real estate investment trust. The costs incurred to acquire and develop properties are included as part of the cost of the properties. Financial Investments and Trading Securities - -------------------------------------------- In Note 3, we summarize the financial investments that are in our Consolidated Balance Sheets. SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities, applies particular requirements to some of our investments in debt and equity securities. We report those investments at fair value, and we use specific identification to determine their cost for computing realized gains or losses. We classify these investments as either trading securities or available-for-sale securities, which we describe separately 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 (loss) 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. 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. See Note 4 for further discussion. 42 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, unless impaired under the provisions of SFAS No. 121. Our original cost includes: . material and labor, . contractor costs, . construction overhead costs (where applicable), and . 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 $156 million at December 31, 1999 and $152 million at December 31, 1998. 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 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 $287.5 million at December 31, 1999 and $244.0 million at December 31, 1998. To fund the costs we expect to incur to decommission the plant, we established an external decommissioning trust in accordance with Nuclear Regulatory Commission (NRC) regulations. We report the assets in the trust in "Nuclear decommissioning trust fund" in our Consolidated Balance Sheets. The NRC requires utilities to provide financial assurance that they will accumulate sufficient funds to pay for the cost of nuclear decommissioning based upon either a generic NRC formula or a facility-specific decommissioning cost estimate. We use the facility-specific cost estimate for funding these costs and providing the required financial assurance. Allowance for Funds Used During Construction and Capitalized Interest - --------------------------------------------------------------------- Allowance for Funds Used During Construction (AFC) - -------------------------------------------------- We finance utility construction projects with borrowed funds and equity funds. We are allowed by the Maryland PSC to record the costs of these funds as part of the cost of construction projects in our Consolidated Balance Sheets. We do this through the AFC, which we calculate using a rate authorized by the Maryland PSC. We bill our customers for the AFC plus a return after the utility plant is placed in service. The AFC rates are 9.04% for gas plant, 9.35% for common plant, and 9.40% for electric plant. We compound AFC annually. Capitalized Interest - -------------------- With the issuance of the Restructuring Order, we ceased accruing AFC for electric generation-related construction projects and began using SFAS No. 34, Capitalizing Interest Costs, to calculate the cost during construction of debt funds used to finance our electric generation-related construction projects. Our diversified businesses capitalize interest costs incurred to finance real estate developed for internal use and certain power projects. 43 Long-Term Debt - -------------- We defer (include as an asset or liability in our Consolidated Balance Sheets and exclude from our Consolidated Statements of Income) all costs related to the issuance of long-term debt. These costs include underwriters' commissions, discounts or premiums, and other costs such as legal, accounting, and regulatory fees, and printing costs. We amortize these costs over the life of the debt. When we incur gains or losses on debt that we retire prior to maturity in our regulated utility business, we amortize those gains or losses over the remaining original life of the debt. 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: . our reported amounts of assets and liabilities in our Consolidated Balance Sheets at the dates of the financial statements, . our disclosure of contingent assets and liabilities at the dates of the financial statements, and . our reported amounts of revenues and expenses in our Consolidated Statements of Income during the reporting periods. These estimates involve judgments with respect to, among other things, future economic factors that are difficult to predict and are beyond management's control. As a result, actual amounts could differ from these estimates. Reclassifications - ----------------- We have reclassified certain prior-year amounts for comparative purposes. These reclassifications did not affect consolidated net income for the years presented. Accounting Standards Issued - --------------------------- In July 1999, the FASB issued SFAS No. 137 that delays the effective date for SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, by one year. Therefore, we must adopt the provisions of SFAS No. 133 in our financial statements for the quarter ended March 31, 2001. We have not determined the effects of SFAS No. 133 on our financial results. - -------------------------------------------------------------------------------- Note 2. - ------- Information by Operating Segment - -------------------------------- We have three reportable operating segments--Electric, Gas, and Energy Services: . Our Electric business generates, purchases, and sells electricity, . Our Gas business purchases, transports, and sells natural gas, and . Our Energy Services businesses consist of certain diversified businesses that: - develop, own, and operate power projects, - provide power marketing and risk management services, - provide nuclear consulting 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: . engage in financial investments, and . develop, own, and manage real estate and senior-living facilities. These reportable segments are strategic businesses based principally upon regulations, products, and services that require different technology and marketing strategies. The segments have the same accounting policies as those described in the summary of significant accounting policies in Note 1. The Company evaluates 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 later in this note. We are realigning our organization combining all of our domestic merchant energy businesses. We have not determined the impact of this reorganization on our operating segments, but such changes will impact our operating segments in the future. 44
Energy Other Unallocated Electric Gas Services Diversified Corporate Business Business Businesses Businesses Items (a) Eliminations Consolidated - ------------------------------------------------------------------------------------------------------------------------------------ (In millions) 1999 - ---- Unaffiliated revenues $2,258.8 $476.5 $ 937.0 $113.9 $ - $ - $3,786.2 Intersegment revenues 1.2 11.6 30.4 (0.4) - (42.8) - - ------------------------------------------------------------------------------------------------------------------------------------ Total revenues 2,260.0 488.1 967.4 113.5 - (42.8) 3,786.2 Depreciation and amortization 376.4 44.9 23.1 5.2 0.2 - 449.8 Equity in income of equity- method investees (b) 5.1 - - - - - 5.1 Net interest expense 162.4 24.4 24.6 31.1 0.4 (1.4) 241.5 Income tax expense (benefit) 149.2 18.1 34.8 (12.1) (0.9) (2.7) 186.4 Extraordinary loss 66.3 - - - - - 66.3 Net income (loss) (c) 198.8 33.0 50.6 (19.3) (1.7) (1.3) 260.1 Segment assets 6,312.6 915.3 1,681.2 743.2 129.2 (97.7) 9,683.8 Utility construction expenditures 322.1 63.8 - - - - 385.9 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 income 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) (d) 259.6 26.1 43.4 (24.2) (0.1) 1.1 305.9 Segment assets 6,342.8 934.6 1,315.0 811.6 (14.0) (115.0) 9,275.0 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 income 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) (e) 224.0 25.6 27.5 (21.1) (3.6) 1.7 254.1 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
(a) We do not allocate certain items presented in the table for Constellation Energy Group and a holding company for our diversified businesses. (b) Our Energy Services and our Other Diversified businesses record their equity in the income of equity method investees in their unaffiliated revenues. (c) Our Electric business recorded costs of $4.9 million after-tax related to Hurricane Floyd as discussed in the "Electric Operations and Maintenance Expenses" section of Management's Discussion and Analysis. Our Other Diversified businesses recorded a $16.0 million write-down of its investment in Capital Re stock to reflect the market value of this investment as discussed in Note 3 and a $5.8 million write-down of certain senior-living facilities as discussed in the "Other Diversified Businesses" section of Management's Discussion and Analysis. In addition, our Energy Services businesses recorded $18.7 million in write-downs of certain power projects as discussed in Note 3. (d) 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. (e) Our Electric business recorded a $37.5 million write-off related to the terminated merger with Potomac Electric Power Company as discussed in the "Other Income and Expenses" 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. 45 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, 1999 1998 - -------------------------------------------------------------- (In millions) Properties under development $197.8 $210.6 Rental and operating properties (net of accumulated depreciation) 9.2 38.9 Equity interest in real estate investment trust 103.1 104.0 Other real estate ventures - 0.4 - -------------------------------------------------------------- Total real estate projects and investments $310.1 $353.9 ============================================================== In 1999, CREG sold Church Street Station --an entertainment, dining, and retail complex in Orlando, Florida --for $11.5 million, the approximate book value of the complex. In 1998, CREG recorded a $15.4 million after-tax write-down of the investment in Church Street Station that occurred because the fair value of the project declined based upon competitive bids. In 1998, CREG entered into an agreement with Corporate Office Properties Trust (COPT), a real estate investment trust based in Philadelphia, under which COPT assumed approximately $62 million of CREG's outstanding debt, paid CREG approximately $22.8 million in cash, and issued to CREG approximately 7.0 million common shares representing a 41.9% equity interest in COPT and 985,000 convertible preferred shares. Each convertible preferred share yields 5.5% per year, and is convertible after two years from the date of the agreement into 1.8748 common shares. In exchange, COPT received 14 operating properties and two properties under development from CREG as well as certain other assets, options, and first refusal rights. These options and first refusal rights are related to approximately 91 acres of identified properties which are adjacent to operating properties acquired by COPT. At December 31, 1999, 48 acres remain under these options and first refusal rights and have terms that range from 1 to 4 years. In 1997, CREG recorded the following write-downs of real estate projects: . a $14.1 million after-tax write-down of the investment in Church Street Station that occurred because CREG decided to sell rather than keep the project, and . a $31.9 million after-tax write-down of the investment in Piney Orchard--a mixed-use, planned-unit development-- that 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, 1999 1998 - -------------------------------------------------- (In millions) Domestic East $ 55.7 $ 46.0 West 475.6 427.4 International South America 12.3 21.6 Central America 241.8 248.1 - -------------------------------------------------- Total power projects $785.4 $743.1 ================================================== Our Domestic-West power projects include investments of $301.8 million in 1999 and $310.6 in 1998 that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. We discuss these projects further in Note 10. In 1999, our power projects business recorded a $14.2 million after-tax write- off of two geothermal power projects. These write-offs occurred because the expected future cash flows from the projects are less than the investment in the projects. For the first project, this resulted from the inability to restructure certain project agreements. For the second project, we experienced a declining water temperature of the geothermal resource used by one of the plants for production. In 1999, we recorded a $4.5 million after-tax write-down to reflect the fair value of our investment in a generating company in Bolivia as a result of our international exit strategy. In 1998, our power projects business recorded $10.4 million after-tax gain for its share of earnings in a partnership. The partnership recognized a gain on the sale of its ownership interest in a power sales contract. 46 Financial Investments - --------------------- Financial investments held by Constellation Investments, Inc. consist of the following: At December 31, 1999 1998 - -------------------------------------------------------------- (In millions) Insurance company $ - $102.5 Marketable equity securities 84.2 25.3 Financial limited partnerships 35.8 41.9 Leveraged leases 25.4 28.3 - -------------------------------------------------------------- Total financial investments $145.4 $198.0 ============================================================== In 1999, our financial investments business announced that it would exchange its shares of common stock in Capital Re, an insurance company, for common stock of ACE Limited (ACE), another insurance company, as part of a business combination whereby ACE would acquire all of the outstanding capital stock of Capital Re. Through September 30, 1999, our financial investments business wrote-down its $94.2 million investment in Capital Re stock by $20.9 million after-tax to reflect the market value of this investment. The agreement between ACE and Capital Re was subsequently revised on a more favorable basis for Capital Re to include both cash and ACE stock. In December 1999, the transaction was finalized and our financial investments business recorded a $4.9 million after-tax gain on this investment to reflect the closing price of the business combination. As a result of this business combination, this investment no longer qualifies as an equity-method investment. Accordingly, in 1999, we have included this investment in the Marketable equity securities amount above. 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 (shown above) as available-for-sale. This means we do not expect to hold them to maturity and we do not consider them trading securities. We show the fair values, gross unrealized gains and losses, and amortized cost bases for all of our available-for-sale securities, exclusive of $6.2 million in 1998 of unrealized net gains on securities held by Capital Re as an equity method investee, in the following tables. Amortized Unrealized Unrealized Fair At December 31, 1999 Cost Basis Gains Losses Value - --------------------------------------------------------------------------- (In millions) Marketable equity securities $167.1 $42.8 $ (2.1) $207.8 Corporate debt and U.S. Government agency 14.4 - - 14.4 State municipal bonds 74.2 - (0.8) 73.4 - --------------------------------------------------------------------------- Totals $255.7 $42.8 $ (2.9) $295.6 =========================================================================== 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 Corporate debt and 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 =========================================================================== The above tables include $40.5 million in 1999 and $23.9 million in 1998 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: 1999 1998 1997 - ---------------------------------------------------------------------------- (In millions) Gross realized gains $ 11.7 $ 4.2 $ 9.3 Gross realized losses (38.8) (0.7) (0.6) - ---------------------------------------------------------------------------- Net realized (losses) gains $(27.1) $ 3.5 $ 8.7 ============================================================================ The Corporate debt securities, U.S. Government agency obligations, and state municipal bonds mature on the following schedule: At December 31, 1999 Amount - ----------------------------------------------------------- (In millions) Less than 1 year $ 1.0 1-5 years 46.4 5-10 years 21.8 More than 10 years 18.6 - ----------------------------------------------------------- Total maturities of debt securities $87.8 =========================================================== 47 Note 4. - ------- Rate Matters and Accounting Impacts of Deregulation - --------------------------------------------------- On April 8, 1999, Maryland enacted the Electric Customer Choice and Competition Act of 1999 (the "Act") and accompanying tax legislation that will significantly restructure Maryland's electric utility industry and modify the industry's tax structure. In the Restructuring Order discussed below, the Maryland PSC addressed the major provisions of the Act. The tax legislation made comprehensive changes to the state and local taxation of electric and gas utilities. Effective January 1, 2000, the Maryland public service franchise tax will be altered to generally include a tax equal to .062 cents on each kilowatt-hour of electricity and .402 cents on each therm of natural gas delivered for final consumption in Maryland. The Maryland 2% franchise tax on electric and natural gas utilities will continue to apply to transmission and distribution revenue. Additionally, all electric and natural gas utility results will become subject to the Maryland corporate income tax. Beginning July 1, 2000, the tax legislation also provides for a two-year phase- in of a 50% reduction in the local personal property taxes on machinery and equipment used to generate electricity for resale and a 60% corporate income tax credit for real property taxes paid on those facilities. On November 10, 1999, the Maryland PSC issued a Restructuring Order that resolves the major issues surrounding electric restructuring, accelerates the timetable for customer choice, and addresses the major provisions of the Act. The Restructuring Order also resolves the electric restructuring proceeding (transition costs, customer price protections, and unbundled rates for electric services) and a petition filed in September 1998 by the Office of People's Counsel (OPC) to lower our electric base rates. The major provisions of the Restructuring Order are: . All customers, except a few commercial and industrial companies that have signed contracts with BGE, will be able to choose their electric energy supplier beginning July 1, 2000. BGE will provide a standard offer service for customers that do not select an alternative supplier. In either case, BGE will continue to deliver electricity to all customers in areas traditionally served by BGE. . BGE's current electric base rates are frozen at their current levels until July 1, 2000. . BGE will reduce residential base rates by approximately 6.5% on average, about $54 million a year, beginning July 1, 2000. These rates will not change before July 2006. . Commercial and industrial customers will have up to four service options that will fix electric energy rates and transition charges for a period that generally ranges from four to six years. . Electric delivery service rates will be frozen for a four year period for commercial and industrial customers. The generation and transmission components of rates will be frozen for different time periods depending on the service options selected by those customers through June 30, 2004. . BGE will be allowed to recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through a competitive transition charge on customers' bills. Residential customers will pay this charge for six years. Commercial and industrial customers will pay in a lump sum or over the four to six-year period, depending on the service option selected by each customer. . Generation-related regulatory assets and nuclear decommissioning costs will be included in delivery service rates effective July 1, 2000 and will be recovered on a basis approximating their existing amortization schedules. . Starting July 1, 2000, BGE will unbundle rates to show separate components for delivery service, transition charges, standard offer services (generation), transmission, universal service, and taxes. . On July 1, 2000, BGE will transfer, at book value, its ten Maryland-based fossil and nuclear power plants and its partial ownership interest in two coal plants and a hydroelectric plant in Pennsylvania to nonregulated subsidiaries of Constellation Energy. . BGE will reduce its generation assets, as described later in this section, by $150 million pre-tax during the period July 1, 1999 - June 30, 2000 to mitigate a portion of its potentially stranded investments. . Universal service will be provided for low-income customers without increasing their bills. BGE will provide its share of a statewide fund totaling $34 million annually. 48 As discussed in Note 1, EITF 97-4 requires that a company should cease applying SFAS No. 71 when either legislation is passed or a regulatory body issues an order that contains sufficient detail to determine how the transition plan will affect the deregulated portion of the business. Additionally, a company would continue to recognize regulatory assets and liabilities in the Consolidated Balance Sheets to the extent that the transition plan provides for their recovery. We believe that the Restructuring Order provided sufficient details of the transition plan to competition for BGE's electric generation business to require BGE to discontinue the application of SFAS No. 71 for that portion of its business. Accordingly, in the fourth quarter of 1999, we adopted the provisions of SFAS No. 101 and EITF 97-4 for BGE's electric generation business. SFAS No. 101 requires the elimination of the effects of rate regulation that have been recognized as regulatory assets and liabilities pursuant to SFAS No. 71. However, EITF 97-4 requires that regulatory assets and liabilities that will be recovered in the regulated portion of the business continue to be classified as regulatory assets and liabilities. The Restructuring Order provides for the creation of a single, new generation-related regulatory asset to be recovered through BGE's regulated transmission and distribution business. We discuss this further in Note 5. Pursuant to SFAS No. 101, the book value of property, plant, and equipment may not be adjusted unless those assets are impaired under the provisions of SFAS No. 121. The process of evaluating and measuring impairment under the provisions of SFAS No. 121 involves two steps. First, we must compare the net book value of each generating plant to the estimated undiscounted future net operating cash flows from that plant. An electric generating plant is considered impaired when its undiscounted future net operating cash flows are less than its net book value. Second, we compute the fair value of each plant that is determined to be impaired based on the present value of that plant's estimated future net operating cash flows discounted using an interest rate that considers the risk of operating that facility in a competitive environment. To the extent that the net book value of each impaired electric generation plant exceeds its fair value, we must record a write-down. Under the Restructuring Order, BGE will recover $528 million after-tax of its potentially stranded investments and utility restructuring costs through the competitive transition charge component of its customer rates beginning July 1, 2000. This recovery mostly relates to the stranded costs associated with Calvert Cliffs, whose book value is substantially higher than its estimated fair value. However, Calvert Cliffs is not considered impaired under the provisions of SFAS No. 121 since its estimated future undiscounted cash flows exceed its book value. Accordingly, BGE did not record any impairment write-down related to Calvert Cliffs. However, we recognized after-tax impairment losses totaling $115.8 million associated with certain of our fossil plants under the provisions of SFAS No. 121. BGE has contracts to purchase electric capacity and energy that are expected to be uneconomic upon the deregulation of electric generation. Therefore, we recorded a $34.2 million after-tax charge based on the net present value of the excess of estimated contract costs over the market-based revenues to recover these costs over the remaining terms of the contracts. In addition, BGE has deferred certain energy conservation expenditures that will not be recovered through its transmission and distribution business under the Restructuring Order. Accordingly, we recorded a $10.3 million after-tax charge to eliminate the regulatory asset previously established for these deferred expenditures. At December 31, 1999, the total charge for BGE's electric generating plants that are impaired, losses on uneconomic purchased capacity and energy contracts, and deferred energy conservation expenditures was approximately $160.3 million after-tax. BGE recorded approximately $94.0 million of the $160.3 million on its balance sheet. This consisted of a $150.0 million regulatory asset of its regulated transmission and distribution business, net of approximately $56.0 million of associated deferred income taxes. The regulatory asset will be amortized as it is recovered from ratepayers through June 30, 2000. This will accomplish the $150 million reduction of its generation plants required by the Restructuring Order. We recorded an after-tax, extraordinary charge against earnings for approximately $66.3 million related to the remaining portion of the $160.3 million described above that will not be recovered under the Restructuring Order. 49 Note 5. - ------- Regulatory Assets (net) - ----------------------- As discussed in Note 1, the Maryland PSC provides the final determination of the rates we charge our customers for our regulated businesses. Generally, we use the same accounting policies and practices used by nonregulated companies for financial reporting under 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 regulatory assets and liabilities in the following table, and we discuss each of them separately below. At December 31, 1999 1998 - ------------------------------------------------------------------------ (In millions) Generation plant reduction recoverable in current rates $ 75.0 $ - Electric generation-related regulatory asset 286.6 - Income taxes recoverable through future rates (net) 110.4 252.6 Deferred postretirement and postemployment benefit costs 41.9 90.0 Deferred nuclear expenditures - 73.3 Deferred conservation expenditures 12.9 53.4 Deferred costs of decommissioning federal uranium enrichment facilities - 38.5 Deferred environmental costs 31.3 33.4 Deferred fuel costs (net) 73.8 12.7 Other (net) 5.5 11.8 - ------------------------------------------------------------------------ Total regulatory assets (net) $637.4 $565.7 ======================================================================== Generation Plant Reduction Recoverable in Current Rates - ------------------------------------------------------- As a condition of the Maryland PSC's consolidation of the September 3, 1998 Office of People's Counsel petition to lower electric base rates with BGE's electric restructuring transition proposal, we agreed to make our rates subject to refund effective July 1, 1999. Under the Restructuring Order, BGE's rates are frozen through June 30, 2000. However, BGE was required to record a reduction to its generation plant of $150 million which it will recover through its current rates between July 1, 1999 and June 30, 2000. BGE recorded a $150 million regulatory asset for the required generation plant reduction that will be amortized as it is recovered from ratepayers through June 30, 2000. Electric Generation-Related Regulatory Asset - -------------------------------------------- With the issuance of the Restructuring Order, BGE no longer met the requirements for the application of SFAS No. 71 for the electric generation portion of its business. In accordance with SFAS No. 101 and EITF 97-4, all individual generation-related regulatory assets and liabilities must be eliminated from our balance sheet unless these regulatory assets and liabilities will be recovered in the regulated portion of the business. Pursuant to the Restructuring Order, BGE wrote-off all of its individual, generation-related regulatory assets and liabilities. A single, new generation-related regulatory asset was established for amounts to be collected through BGE's regulated transmission and distribution business. The new regulatory asset will be amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. Income Taxes Recoverable Through Future Rates (net) - --------------------------------------------------- As described in Note 1, income taxes recoverable through future rates is 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. In 1999, the electric generation-related portion of this regulatory asset is included in the electric generation-related regulatory asset discussed earlier in this note. 50 Deferred Postretirement and Postemployment Benefit Costs - -------------------------------------------------------- Deferred postretirement and postemployment benefit costs are the costs we recorded under SFAS No. 106 (for postretirement benefits) and No. 112 (for postemployment benefits) in excess of the costs we included in the rates we charge our customers. We began amortizing these costs over a 15-year period in 1998. We discuss these costs further in Note 6. In 1999, we reclassified the electric generation-related portion of this regulatory asset to the electric generation-related regulatory asset discussed earlier in this note. Deferred Nuclear Expenditures - ----------------------------- Deferred nuclear expenditures are the net unamortized balance of certain operations and maintenance costs at Calvert Cliffs. These expenditures consist of: . costs incurred from 1979 through 1982 for inspecting and repairing seismic pipe supports, . expenditures incurred from 1989 through 1994 associated with nonrecurring phases of certain nuclear operations projects, and . expenditures incurred during 1990 for investigating leaks in the pressurizer heater sleeves. In 1999, these expenditures were reclassified to the electric generation-related regulatory asset discussed earlier in this note. Deferred Conservation Expenditures - ---------------------------------- Deferred conservation expenditures include two components: . operations costs (labor, materials, and indirect costs) associated with conservation programs approved by the Maryland PSC, which we are amortizing over periods of four to five years in accordance with the Maryland PSC's orders, and . revenues we collected from customers in 1996 in excess of our profit limit under the conservation surcharge. In 1999, we wrote-off a portion of the unamortized electric conservation expenditures that will not be recovered under the Restructuring Order as discussed in Note 4. Deferred 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. In 1999, these expenditures were reclassified to the electric generation-related regulatory asset discussed earlier in this note. 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, 1999 1998 - ------------------------------------------------------------------- (In millions) Electric $60.0 $(11.5) Gas 13.8 24.2 - ------------------------------------------------------------------- Deferred fuel costs (net) $73.8 $ 12.7 =================================================================== Under the Restructuring Order, BGE's electric fuel rate clause will be discontinued effective July 1, 2000. After that date, earnings will be affected by the changes in the cost of fuel and energy. In addition, any accumulated difference between our actual costs of fuel and energy and the amounts collected from customers under the electric fuel rate clause will be collected from our customers over a period to be determined by the Maryland PSC. 51 Note 6. - ------- Pension, Postretirement, Other Postemployment, and Employee Savings Plan - ------------------------------------------------------------------------ Benefits - -------- We offer pension, postretirement, other postemployment, and employee savings plan benefits. We describe each of these separately below. Pension Benefits - ---------------- We sponsor several defined benefit pension plans for our employees. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. Our employees do not contribute to these plans. Generally, we calculate the benefits under these plans based on age, years of service, and pay. Sometimes we amend the plans retroactively. These retroactive plan amendments require us to recalculate benefits related to participants' past service. We amortize the change in the benefit costs from these plan amendments on a straight-line basis over the average remaining service period of active employees. In 1999, our Board of Directors approved the following amendments: . eligible participants will be allowed to choose between an enhanced version of the current benefit formula and a new pension equity plan (PEP) formula. Pension benefits for eligible employees hired after December 31, 1999 will be based on a PEP formula, and . pension and survivor benefits were increased for participants who retired prior to January 1, 1994 and for their surviving spouses. The financial impacts of the amendments are included in the tables in this section. Also during 1999, our Board of Directors approved a Targeted Voluntary Special Early Retirement Program (TVSERP) to provide enhanced early retirement benefits to certain eligible participants in targeted jobs that elect to retire on June 1, 2000. The financial impacts of the TVSERP will be reflected in the second quarter of 2000. 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, 1999 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 Constellation Energy and BGE employees, and certain employees of our subsidiaries. Generally, we calculate the benefits under these plans based on age, years of service, and pension benefit levels. We do not fund these plans. For nearly all of the health care plans, retirees make contributions to cover a portion of the plan costs. Contributions for employees who retire after June 30, 1992 are calculated based on age and years of service. The amount of retiree contributions increases based on expected increases in medical costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs. Effective January 1, 1993, we adopted SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. The adoption of that statement caused: . a transition obligation, which we are amortizing over 20 years, and . an increase in annual postretirement benefit costs. For our 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: . in an April 1993 rate order, the Maryland PSC allowed us to expense one- half and defer, as a regulatory asset (see Note 5), the other half of the increase in annual postretirement benefit costs related to our electric and gas businesses, and . 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: . expense all of the increase in annual postretirement benefit costs related to our electric business, and . amortize the regulatory asset for postretirement benefit costs related to our electric and gas businesses over 15 years. 52 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:
Pension Postretirement Benefits Benefits 1999 1998 1999 1998 - ----------------------------------------------------------------------------------------- (In millions) Change in benefit obligation - ---------------------------- Benefit obligation at January 1 $1,031.3 $ 902.0 $ 383.1 $ 320.3 Service cost 26.1 21.6 8.6 6.6 Interest cost 65.3 63.0 24.4 23.4 Plan participants' contributions - - 2.0 2.0 Actuarial (gain) loss (93.0) 102.9 (34.2) 48.9 Plan amendments 44.6 - (5.0) - Benefits paid (57.6) (58.2) (20.2) (18.1) - ----------------------------------------------------------------------------------------- Benefit obligation at December 31 $1,016.7 $1,031.3 $ 358.7 $ 383.1 ========================================================================================= Pension Postretirement Benefits Benefits 1999 1998 1999 1998 - ----------------------------------------------------------------------------------------- (In millions) Change in plan assets - --------------------- Fair value of plan assets at January 1 $ 985.5 $ 912.3 $ - $ - Actual return on plan assets 139.4 116.9 - - Employer contribution 17.6 14.5 18.2 16.1 Plan participants' contributions - - 2.0 2.0 Benefits paid (57.6) (58.2) (20.2) (18.1) - ----------------------------------------------------------------------------------------- Fair value of plan assets at December 31 $1,084.9 $ 985.5 $ - $ - ========================================================================================= Pension Postretirement Benefits Benefits 1999 1998 1999 1998 - ----------------------------------------------------------------------------------------- (In millions) Funded Status - ------------- Funded status at December 31 $ 68.2 $ (45.8) $(358.7) $(383.1) Unrecognized net actuarial (gain) loss (27.2) 137.6 23.6 59.7 Unrecognized prior service cost 59.0 16.9 (0.1) - Unrecognized transition obligation - - 143.4 159.3 Unamortized net asset from adoption of SFAS No. 87 (0.5) (0.7) - - - ----------------------------------------------------------------------------------------- Prepaid (accrued) benefit cost $ 99.5 $ 108.0 $(191.8) $(164.1) =========================================================================================
Net Periodic Benefit Cost - ------------------------- We show the components of net periodic pension benefit cost in the following table:
Year Ended December 31, 1999 1998 1997 - ------------------------------------------------------------------------------------ (In millions) Components of net periodic - -------------------------- pension benefit cost -------------------- Service cost $ 26.1 $ 21.6 $ 16.8 Interest cost 65.3 63.0 61.3 Expected return on plan assets (76.6) (72.1) (66.9) Amortization of transition obligation (0.2) (0.2) (0.2) Amortization of prior service cost 2.5 2.5 2.5 Recognized net actuarial loss 10.1 5.6 4.6 Amount capitalized as construction cost (4.2) (3.8) (2.5) - ------------------------------------------------------------------------------------ Net periodic pension benefit cost $ 23.0 $ 16.6 $ 15.6 ====================================================================================
53 We show the components of net periodic postretirement benefit cost in the following table: Year Ended December 31, 1999 1998 1997 - ---------------------------------------------------------------------------- (In millions) Components of net periodic - -------------------------- postretirement benefit cost --------------------------- Service cost $ 8.6 $ 6.6 $ 5.4 Interest cost 24.4 23.4 21.8 Amortization of transition obligation 11.0 11.4 11.4 Recognized net actuarial loss 1.9 0.2 0.1 Amount capitalized as construction cost (9.4) (8.1) (7.6) Amount deferred - - (7.2) - ---------------------------------------------------------------------------- Net periodic postretirement benefit cost $36.5 $33.5 $23.9 ============================================================================ Assumptions - ----------- We made the assumptions below to calculate our pension and postretirement benefit obligations. Pension Postretirement Benefits Benefits At December 31, 1999 1998 1999 1998 - ------------------------------------------------------------ Discount rate 7.25% 6.50% 7.25% 6.50% Expected return on plan assets 9.00 9.00 N/A N/A Rate of compensation increase 4.00 4.00 4.00 4.00 We assumed the health care inflation rates to be: . in 1999, 6.0% for both Medicare-eligible retirees and retirees not covered by Medicare, and . in 2000, 7.0% for Medicare-eligible retirees and 8.5% for retirees not covered by Medicare. After 2000, we assumed both inflation rates will decrease by 0.5% annually to a rate of 5.5% in the years 2003 and 2006, respectively. After these dates, the inflation rate will remain at 5.5%. A one-percent increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $46.7 million as of December 31, 1999 and would increase the combined service and interest costs of the postretirement benefit cost by approximately $5.4 million annually. A one-percent decrease in the health care inflation rate from the assumed rates would decrease the accumulated postretirement benefit obligation by approximately $37.4 million as of December 31, 1999 and would decrease the combined service and interest costs of the postretirement benefit cost by approximately $4.2 million annually. Other Postemployment Benefits - ----------------------------- We provide the following postemployment benefits: . health and life insurance benefits to our employees and certain employees of our subsidiaries who are found to be disabled under our Disability Insurance Plan, and . income replacement payments for employees found to be disabled before November 1995 (payments for employees found to be disabled after that date are paid by an insurance company, and the cost is paid by employees). The liability for these benefits totaled $46.5 million as of December 31, 1999 and $52.9 million as of December 31, 1998. Effective December 31, 1993, we adopted SFAS No. 112, Employers' Accounting for Postemployment Benefits. We deferred, as a regulatory asset (see Note 5), the postemployment benefit liability attributable to our utility business as of December 31, 1993, consistent with the Maryland PSC's orders for postretirement benefits (described earlier in this note). We began to amortize the regulatory asset over 15 years beginning in 1998. The Maryland PSC authorized us to reflect this change in our current electric and gas base rates to recover the higher costs in 1998. We assumed the discount rate for other postemployment benefits to be 5.5% in 1999 and 4.5% in 1998. Employee Savings Plan Benefits - ------------------------------ We also sponsor a defined contribution savings plan that is offered to all eligible Constellation Energy and 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: . $10.4 million in 1999, . $10.1 million in 1998, and . $8.5 million in 1997. 54 Note 7. - ------- 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 issuance. We pay commitment fees to banks for providing us lines of credit. When we borrow under the lines of credit, we pay market interest rates. Constellation Energy - -------------------- At December 31, 1999, Constellation Energy had $242.5 million outstanding consisting entirely of commercial paper notes. At December 31, 1998, no short- term borrowings were outstanding since Constellation Energy was not established until April 30, 1999 as discussed in Note 1. In 1999, Constellation Energy arranged a $135 million revolving credit agreement for short-term financial needs, including letters of credit. This agreement also supports Constellation Energy's commercial paper notes. This facility replaced a similar facility at one of Constellation Energy's diversified businesses. At December 31, 1999, letters of credit totaling $23.1 million were issued under this facility. In addition, Constellation Energy had unused committed bank lines of credit totaling $35 million and interim lines totaling $125 million supporting its commercial paper notes at December 31, 1999. The weighted average effective interest rate for Constellation Energy's commercial paper notes was 5.68% for the year ended December 31, 1999. BGE - --- At December 31, 1999, BGE had $129.0 million outstanding consisting entirely of commercial paper notes. At December 31, 1998, BGE had no short-term borrowings outstanding. At December 31, 1999, BGE had unused committed bank lines of credit totaling $123 million supporting the commercial paper notes compared to $113 million at December 31, 1998. These amounts do not include unused revolving credit agreements of $60 million at December 31, 1999 and $100 million at December 31, 1998 that are discussed in Note 8. The weighted average effective interest rates for BGE's commercial paper notes were 5.25% for the year ended December 31, 1999 and 5.65% for 1998. - ------------------------------------------------------------------------------- Note 8. - ------- Long-Term Debt - -------------- Long-term debt matures in one year or more from the date of issuance. We summarize our long-term debt in the Consolidated Statements of Capitalization. As you read this section, it may be helpful to refer to those statements. BGE - --- 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. Capital stock pledged under the mortgage is that of Safe Harbor Water Power Corporation and Constellation Enterprises, Inc. When BGE transfers its generating assets to subsidiaries of Constellation Energy, these assets will remain subject to the lien of BGE's mortgage. However, BGE will remain liable for this debt after the assets are transferred. 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: . 5 1/2% Installment Series, due 2002 . 6 1/8% Series, due 2003 . 5 1/2% Series, due 2000 . 5 1/2% Series, due 2004 . 8 3/8% Series, due 2001 . 7 1/2% Series, due 2007 . 7 1/4% Series, due 2002 . 6 5/8% Series, due 2008 . 6 1/2% Series, due 2003 Holders of the Remarketed Floating Rate Series Due September 1, 2006 have the option to require BGE to repurchase their bonds at face value on September 1 of each year. BGE is required to repurchase and retire at par any bonds that are not remarketed or purchased by the remarketing agent. BGE also has the option to redeem all or some of these bonds at face value each September 1. 55 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, 1999 in the following table. Weighted-Average Series Interest Rate Maturity Dates - ---------------------------------------------------- B 8.10% 2000-2006 C 7.33 2000-2003 D 6.66 2001-2006 E 6.66 2006-2012 G 6.08 2001-2008 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 $60 million of revolving credit agreements with several banks that are available through 2000. At December 31, 1999, 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 7. BGE Obligated Mandatorily Redeemable - ------------------------------------ Trust Preferred Securities - -------------------------- On June 15, 1998, BGE Capital Trust I (Trust), a Delaware business trust established by BGE, issued 10,000,000 Trust Originated Preferred Securities (TOPrS) for $250 million ($25 liquidation amount per preferred security) with a distribution rate of 7.16%. The Trust used the net proceeds from the issuance of the common securities and the preferred securities to purchase a series of 7.16% Deferrable Interest Subordinated Debentures due June 30, 2038 (debentures) from BGE in the aggregate principal amount of $257.7 million with the same terms as the TOPrS. The Trust must redeem the TOPrS at $25 per preferred security plus accrued but unpaid distributions when the debentures are paid at maturity or upon any earlier redemption. BGE has the option to redeem the debentures at any time on or after June 15, 2003 or at any time when certain tax or other events occur. The interest paid on the debentures, which the Trust will use to make distributions on the TOPrS, is included in "Interest Expense" in the Consolidated Statements of Income and is deductible for income tax purposes. BGE fully and unconditionally guarantees the TOPrS based on its various obligations relating to the trust agreement, indentures, debentures, and the preferred security guarantee agreement. The debentures are the only assets of the Trust. The Trust is wholly owned by BGE because it owns all the common securities of the Trust that have general voting power. For the payment of dividends and in the event of liquidation of BGE, the debentures are ranked prior to preference stock and common stock. Diversified Businesses - ---------------------- 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, 1999, ComfortLink had $33 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: . 7.90%, due in 2000 . 9.65%, due in 2028 . 8.00%, due in 2001 . 8.00%, due in 2033 . 4.25%, due in 2009 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. Unsecured Notes - --------------- The unsecured notes mature on the following schedule: Amount - -------------------------------------------------------------------------------- (In millions) 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, 1999 $511.0 =============================================================================== 56 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) 2000 $ 401.9 $ 284.4 2001 282.2 366.6 2002 154.0 1.5 2003 286.8 10.4 2004 154.0 6.0 Thereafter 1,428.6 17.9 - ----------------------------------------------------------------------------- Total long-term debt at December 31, 1999 $2,707.5 $686.8 ============================================================================ At December 31, 1999, BGE had long-term loans totaling $255.0 million that mature after 2002 (including $110.0 million of medium-term notes discussed in this Note under "BGE's Other Long-Term Debt") that lenders could potentially require us to repay early. Of this amount, $145.0 million could be repaid in 2000, $60.0 million in 2002, and $50.0 million thereafter. At December 31, 1999, $122.0 million is classified as current portion of long-term debt as a result of these provisions. Weighted Average Interest Rates for Variable Rate Debt - ------------------------------------------------------ Our weighted average interest rates for variable rate debt were: Year Ended December 31, 1999 1998 - ------------------------------------------------------------------ BGE - --- Floating rate series mortgage bonds 5.41% 5.90% Remarketed floating rate series mortgage bonds 5.19 5.70 Medium-term notes, Series D 5.29 5.74 Medium-term notes, Series G 5.38 - Medium-term notes, Series H 5.64 - Pollution control loan 3.22 3.48 Port facilities loan 3.24 3.61 Adjustable rate pollution control loan 3.59 3.75 Economic development loan 3.26 3.59 Variable rate pollution control loan 3.30 3.45 Diversified Businesses - ---------------------- Loans under credit agreement 5.68 6.02 Mortgage and construction loans 6.65 8.17 - ------------------------------------------------------------------------------- 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. Capital leases are not material in amount. All other leases are operating leases and are reported in the Consolidated Statements of Income. We present information about our operating leases below. Outgoing Lease Payments - ----------------------- We, as lessee, lease some facilities and equipment used in our businesses. The lease agreements expire on various dates and have various renewal options. We expense all lease payments associated with our regulated utility operations. Lease expense was: . $12.2 million in 1999, . $10.5 million in 1998, and . $9.5 million in 1997. At December 31, 1999, we owed future minimum payments for long-term, noncancelable, operating leases as follows: Year (In millions) - --------------------------------------------- 2000 $ 8.2 2001 6.1 2002 4.5 2003 3.2 2004 2.4 Thereafter 9.7 - --------------------------------------------- Total future minimum lease payments $34.1 ============================================= 57 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: . $67.8 million in 1999, . $70.7 million in 1998, and . $65.6 million in 1997. At December 31, 1999, we estimate our future payments for capacity and energy that we are obligated to buy under these contracts to be:
Year (In millions) - ----------------------------------------------------------- 2000 $ 69.7 2001 37.1 2002 13.9 2003 13.8 2004 13.6 Thereafter 113.4 - ----------------------------------------------------------- Total estimated future payments for capacity and energy under long-term contracts $261.5 ===========================================================
Portions of these contracts are expected to be uneconomic upon the deregulation of electric generation. Therefore, we recorded a charge and accrued a corresponding liability based on the net present value of the excess of estimated contract costs over the market based revenues to recover these costs over the remaining terms of the contracts as discussed in Note 4. At December 31, 1999, the accrued portion of these contracts was $47.5 million. 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, 1999, the total amount of investment requirements committed to by our diversified businesses was $174.2 million. This amount includes $121 million for our energy services businesses commitment to Orion Power Holdings, Inc. BGE and BGE Home Products & Services have agreements to sell on an ongoing basis an undivided interest in a designated pool of customer receivables. Under the agreements, BGE can sell up to a total of $40 million, and BGE Home Products & Services can sell up to a total of $50 million. Under the terms of the agreements, the buyer of the receivables has limited recourse against BGE and has no recourse against BGE Home Products & Services. BGE and BGE Home Products & Services have recorded reserves for credit losses. At December 31, 1999, BGE had sold $28.2 million and BGE Home Products & Services had sold $43.3 million of receivables under these agreements. Guarantees - ---------- Constellation Energy has issued guarantees in an amount up to $69.2 million related to credit facilities and contractual performance of certain of its diversified subsidiaries. However, the actual subsidiary liabilities related to these guarantees totaled $21.7 million at December 31, 1999. 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, 1999, Safe Harbor Water Power Corporation had outstanding debt of $20.4 million, of which $13.6 million is guaranteed by BGE. At December 31, 1999, our remaining diversified businesses had guaranteed outstanding loans and letters of credit of certain power projects and real estate projects totaling $48.8 million. Our diversified businesses also guarantee certain other borrowings of various power projects and real estate projects. We assess the risk of loss from these guarantees to be minimal. 58 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 primarily addresses emissions of sulfur dioxides. Compliance is required in two phases: . 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. . Phase II became effective January 1, 2000. We met the compliance requirements through a combination of switching fuels and allowance trading. Title I addresses emissions of NOx. The Maryland Department of the Environment (MDE) has issued regulations, effective October 18, 1999, which require up to 65% NOx emissions reductions by May 1, 2000. We have entered into a settlement agreement with the MDE since we cannot meet this deadline. Under the terms of the settlement agreement, BGE will install emissions reduction equipment at two sites by May 2002. In the meantime, we are taking steps to control NOx emissions at our generating plants. The Environmental Protection Agency (EPA) issued a final rule in September 1998 that requires up to 85% NOx emissions reduction by 22 states including Maryland and Pennsylvania. While the rule was appealed by several groups including utilities and states, Maryland will meet the requirements of the rule by 2003. Based on the MDE and EPA regulations, we currently estimate that the additional controls needed at our generating plants to meet the MDE's 65% NOx emission reduction requirements will cost approximately $135 million. Through December 31, 1999, we have spent approximately $51 million to meet the MDE's 65% reduction requirements. We estimate the additional cost for EPA's 85% reduction requirements to be approximately $35 million by 2003. In July 1997, the EPA published new National Ambient Air Quality Standards for very fine particulates and revised standards for ozone attainment. In 1999, these new standards were successfully challenged in court. The EPA is expected to appeal the 1999 court rulings to the Supreme Court. While these standards may require increased controls at our fossil generating plants in the future, implementation will be delayed for several years. We cannot estimate the cost of these increased controls at this time because the states, including Maryland and Pennsylvania, still need to determine what reductions in pollutants will be necessary to meet the new 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 15.43% 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. On July 12, 1999, the EPA notified us, along with nineteen other entities, that we may be a potentially responsible party at the 68th Street Dump/Industrial Enterprises Site, also known as the Robb Tyler Dump located in Baltimore, Maryland. The EPA indicated that it is proceeding with plans to conduct a remedial investigation and feasibility study. This site was proposed for listing as a federal Superfund site in January 1999, but the listing has not been finalized. Although our potential liability cannot be estimated, we do not expect such liability to be material based on our records showing that we did not send waste to the site. 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 5. Through December 31, 1999, we have spent approximately $34 million for remediation at this site. 59 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). We do not expect the cleanup costs of the remaining sites to have a material effect on our financial results. Nuclear Insurance - ----------------- If there were an accident or an extended outage at either unit of Calvert Cliffs, it could have a substantial adverse financial effect on us. The primary contingencies that would result from an incident at Calvert Cliffs could include: . physical damage to the plant, . recoverability of replacement power costs, and . our liability to third parties for property damage and bodily injury. We have insurance policies that cover these contingencies, but the policies have certain industry standard exclusions. Furthermore, the costs that could result from a covered major accident or a covered extended outage at either of the Calvert Cliffs units could exceed our insurance coverage limits. Insurance for Calvert Cliffs and Third Party Claims - --------------------------------------------------- For physical damage to Calvert Cliffs, we have $2.75 billion of property insurance from an industry mutual insurance company. If an outage at either of the two units at Calvert Cliffs is caused by an insured physical damage loss and lasts more than 12 weeks, we have insurance coverage for replacement power costs up to $490.0 million per unit, provided by an industry mutual insurance company. This amount can be reduced by up to $98.0 million per unit if an outage at both units of the plant is caused by a single insured physical damage loss. If accidents at any insured plants cause a shortfall of funds at the industry mutual insurance company, all policyholders could be assessed, with our share being up to $21.7 million. In addition we, as well as others, could be charged for a portion of any third party claims associated with a nuclear incident at any commercial nuclear power plant in the country. At December 31, 1999, the limit for third party claims from a nuclear incident is $9.34 billion under the provisions of the Price Anderson Act. If third party claims exceed $200 million (the amount of primary insurance), our share of the total liability for third party claims could be up to $176.2 million per incident. That amount would be payable at a rate of $20 million per year. Insurance for Worker Radiation Claims - ------------------------------------- As an operator of a commercial nuclear power plant in the United States, we are required to purchase insurance to cover radiation injury claims of certain nuclear workers. On January 1, 1998, a new insurance policy became effective for all operators requiring coverage for current operations. Waiving the right to make additional claims under the old policy was a condition for acceptance under the new policy. We describe both the old and new policies below. . Nuclear worker claims reported on or after January 1, 1998 are covered by a new insurance policy with an annual industry aggregate limit of $200 million for radiation injury claims against all those insured by this policy. . All nuclear worker claims reported prior to January 1, 1998 are still covered by the old insurance policies. Insureds under the old policies, with no current operations, are not required to purchase the new policy described above, and may still make claims against the old policies for the next eight years. If radiation injury claims under these old policies exceed the policy reserves, all policyholders could be assessed, with our share being up to $6.3 million. If claims under these polices exceed the coverage limits, the provisions of the Price Anderson Act (discussed in this section) would apply. 60 Recoverability of Electric Fuel Costs - ------------------------------------- Until July 1, 2000, we will continue 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 evaluate the performance of our generating plants, and will determine if we used all reasonable and cost-effective maintenance and operating control procedures. 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. Under the terms of the Restructuring Order, BGE's electric fuel rate clause will be discontinued effective July 1, 2000. We discuss competition and its impact on BGE's generation business further in Note 4. The discontinuance of BGE's electric fuel rate clause is discussed further in Note 1. California Power Purchase Agreements - ------------------------------------ Constellation Power, Inc. and subsidiaries and Constellation Investments, Inc. (whose power projects are managed by Constellation Power) have $301.8 million invested in 14 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. Under these agreements, the projects supply electricity to utility companies at: . a fixed rate for capacity and energy for the first 10 years of the agreements, and . a fixed rate for capacity plus a variable rate for energy based on the utilities' avoided cost for the remaining term of the agreements. Generally, a "capacity rate" is paid to a power plant for its availability to supply electricity, and an "energy rate" is paid for the electricity actually generated. "Avoided cost" generally is the cost of a utility's cheapest next- available source of generation to service the demands on its system. We use the term "transitioned" to describe when the 10-year periods for fixed energy rates have expired for these power generation projects and they began supplying electricity at variable rates. The four remaining projects that have not transitioned will do so by December 2000. The projects that have already transitioned to variable rates have had lower revenues under variable rates than they did under fixed rates. Once the remaining projects have transitioned to variable rates, we expect the revenues from those projects also to be lower than they are under fixed rates. We discuss the earnings for these projects in the "Diversified Businesses" section of Management's Discussion and Analysis. 61 Note 11. - -------- Fair Market 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: . 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. . Investments and other assets where it was practicable to estimate fair value: The fair value is based on quoted market prices where available. . 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, and we describe some of the items separately below:
At December 31, 1999 1998 - -------------------------------------------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value - -------------------------------------------------------------------------------- (In millions) Investments and other assets for which it is: Practicable to estimate fair value $ 313.3 $ 313.3 $ 213.0 $ 213.0 Not practicable to estimate fair value 46.7 N/A 56.5 N/A Fixed-rate long-term debt 2,728.9 2,637.3 2,954.7 3,076.6 Redeemable preference stock - - 7.0 7.2
It was not practicable to estimate the fair value of investments held by our diversified businesses in: . several financial partnerships that invest in nonpublic debt and equity securities, and . several partnerships that own solar powered energy production facilities. This is because the timing and amount of cash flows from these investments are difficult to predict. We report these investments at their original cost in our Consolidated Balance Sheets. The investments in financial partnerships totaled $35.8 million at December 31, 1999 and $41.9 million at December 31, 1998, representing ownership interests up to 10%. The total assets of all of these partnerships totaled $5.9 billion at December 31, 1998 (which is the latest information available). The investments in solar powered energy production facility partnerships totaled $10.9 million at December 31, 1999 and 1998, representing ownership interests up to 13%. The total assets of all of these partnerships totaled $31.3 million at December 31, 1998 (which is the latest information available). Guarantees - ---------- It was not practicable to determine the fair value of certain loan guarantees of Constellation Energy and its subsidiaries. Constellation Energy guaranteed outstanding debt of $16.5 million at December 31, 1999. BGE guaranteed outstanding debt of $13.6 million at December 31, 1999 and $18.0 million at December 31, 1998. Our diversified businesses guaranteed outstanding debt totaling $48.8 million at December 31, 1999 and $59.7 million at December 31, 1998. We do not anticipate that we will need to fund these guarantees. 62 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. 1999 Quarterly Data - Constellation Energy - ------------------------------------------
Earnings Earnings Income Applicable Per Share From to Common of Common Revenues Operations Stock Stock - ------------------------------------------------------------------------ (In millions, except per-share amounts) Quarter Ended March 31 $ 932.3 $ 198.1 $ 82.8 $ 0.55 June 30 820.0 163.9 68.0 0.45 September 30 970.4 277.7 136.1 0.91 December 31 1,063.5 120.2 (26.8) (0.18) - ------------------------------------------------------------------------ Year Ended December 31 $3,786.2 $ 759.9 $ 260.1 $ 1.74 ========================================================================
1999 Quarterly Data - BGE - -------------------------
Earnings Income Applicable From to Common Revenues Operations Stock - ------------------------------------------------------------- (In millions) Quarter Ended March 31 $ 932.3 $ 198.1 $ 82.8 June 30 669.2 140.9 57.8 September 30 756.0 283.3 151.5 December 31 670.8 82.0 (43.5) - ------------------------------------------------------------- Year Ended December 31 $3,028.3 $ 704.3 $ 248.6 =============================================================
Constellation Energy's second quarter results include a $3.6 million after-tax write-down of a financial investment (see Note 3). Third quarter results include: Constellation Energy and BGE - ---------------------------- . $7.5 million associated with Hurricane Floyd (see the "Electric Operations and Maintenance Expenses" section of Management's Discussion and Analysis). . a $37.5 million deferral of revenues collected associated with the deregulation of our electric generation business (see Note 5), Constellation Energy - -------------------- . a $17.3 million after-tax write-down of a financial investment (see Note 3), . a $6.7 million after-tax write-off of a power project (see Note 3), and . a $3.4 million after-tax write-down of certain senior-living facilities (see Note 2). Fourth quarter results include: Constellation Energy and BGE - ---------------------------- . a $66.3 million extraordinary charge associated with the Restructuring Order (see Note 4), . the recognition of the $37.5 million of revenues that were deferred in the third quarter (see above), . $75 million in amortization expense for the reduction of our generation plants associated with the Restructuring Order (see the "Electric Depreciation and Amortization Expense" section of Management's Discussion and Analysis), Constellation Energy - -------------------- . a $4.9 million after-tax gain on a financial investment (see Note 3), . $12.0 million after-tax write-downs of certain power projects (see Note 3), and . a $2.4 million after-tax write-down of certain senior-living facilities (see Note 2). 1998 Quarterly Data - Constellation Energy and BGE - --------------------------------------------------
Earnings Earnings Income Applicable Per Share From to Common of Common Revenues Operations Stock Stock - ------------------------------------------------------------------------ (In millions, except per-share amounts) Quarter Ended March 31 $ 866.1 $ 183.4 $ 74.4 $ 0.50 June 30 767.6 156.2 57.4 0.39 September 30 934.0 320.4 160.9 1.08 December 31 790.4 81.1 13.2 0.09 - ------------------------------------------------------------------------ Year Ended December 31 $3,358.1 $ 741.1 $ 305.9 $ 2.06 ========================================================================
Third quarter results include a $10.4 million after-tax gain for earnings in a partnership (see Note 3). Fourth quarter results include: . a $15.4 million after-tax write-off of a real estate investment (see Note 3), and . 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). The sum of the quarterly earnings per share amounts may not equal the total for the year due to the effects of rounding. 63 EX-12 2 EXHIBIT 12A EXHIBIT 12(a) CONSTELLATION ENERGY GROUP, INC. AND SUBSIDIARIES ------------------------------------------------- COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
12 Months Ended ------------------------------------------------------------------------- December December December December December 1999 1998 1997 1996 1995 ------------ ------------ ------------ ------------ ------------ (IN MILLIONS OF DOLLARS) Income from Continuing Operations (Before Extraordinary Charge) $ 326.4 $ 305.9 $ 254.1 $ 272.3 $ 297.4 Taxes on Income, Including Tax Effect for BGE Preference Stock Dividends 182.5 169.3 145.1 148.3 152.0 ------------ ------------ ------------ ------------ ------------ Adjusted Income $ 508.9 $ 475.2 $ 399.2 $ 420.6 $ 449.4 ------------ ------------ ------------ ------------ ------------ Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 245.7 $ 255.3 $ 234.2 $ 203.9 $ 206.7 Earnings required for BGE Preference Stock Dividends 21.0 33.8 45.1 59.4 61.0 Capitalized Interest 2.7 3.6 8.4 15.7 15.0 Interest Factor in Rentals 1.8 1.9 1.9 1.5 2.1 ------------ ------------ ------------ ------------ ------------ Total Fixed Charges $ 271.2 $ 294.6 $ 289.6 $ 280.5 $ 284.8 ------------ ------------ ------------ ------------ ------------ Earnings (1) $ 777.4 $ 766.2 $ 680.4 $ 685.4 $ 719.2 ============ ============ ============ ============ ============ Ratio of Earnings to Fixed Charges 2.87 2.60 2.35 2.44 2.52
(1) Earnings are deemed to consist of income from continuing operations (before extraordinary charge) that includes earnings of Constellation Energy's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes, investment tax credit adjustments, and the tax effect of BGE's preference stock dividends), and fixed charges other than capitalized interest. EX-12 3 EXHIBIT 12B EXHIBIT 12(b) BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES --------------------------------------------------- COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
12 Months Ended ---------------------------------------------------------------------------- December December December December December 1999 1998 1997 1996 1995 ------------ ------------ ------------ ------------ ------------ (IN MILLIONS OF DOLLARS) Income from Continuing Operations (Before Extraordinary Charge) $ 328.4 $ 327.7 $ 282.8 $ 310.8 $ 338.0 Taxes on Income 182.0 181.3 161.5 169.2 172.4 ------------ ------------ ------------ ------------ ------------ Adjusted Income $ 510.4 $ 509.0 $ 444.3 $ 480.0 $ 510.4 ------------ ------------ ------------ ------------ ------------ Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $ 206.4 $ 255.3 $ 234.2 $ 203.9 $ 206.7 Capitalized Interest 0.4 3.6 8.4 15.7 15.0 Interest Factor in Rentals 1.0 1.9 1.9 1.5 2.1 ------------ ------------ ------------ ------------ ------------ Total Fixed Charges $ 207.8 $ 260.8 $ 244.5 $ 221.1 $ 223.8 ------------ ------------ ------------ ------------ ------------ Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends $ 13.5 $ 21.8 $ 28.7 $ 38.5 $ 40.6 Income Tax Required 7.5 12.0 16.4 20.9 20.4 ------------ ------------ ------------ ------------ ------------ Total Preferred and Preference Dividend Requirements $ 21.0 $ 33.8 $ 45.1 $ 59.4 $ 61.0 ------------ ------------ ------------ ------------ ------------ Total Fixed Charges and Preferred and Preference Dividend Requirements $ 228.8 $ 294.6 $ 289.6 $ 280.5 $ 284.8 ============ ============ ============ ============ ============ Earnings (2) $ 717.8 $ 766.2 $ 680.4 $ 685.4 $ 719.2 ============ ============ ============ ============ ============ Ratio of Earnings to Fixed Charges 3.45 2.94 2.78 3.10 3.21 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 3.14 2.60 2.35 2.44 2.52
(1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock. (2) Earnings are deemed to consist of income from continuing operations (before extraordinary charge) that 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. EX-23 4 CONSENT Exhibit 23 CONSENT OF INDEPENDENT ACCOUNTANTS ---------------------------------- We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 and Form S-8 (File Nos. 333-75217, 333-59601, 33-57658, 333-24705, and 33-49801 and 333-45051, 33-59545, and 33-56084, respectively) of Constellation Energy Group, Inc. and Form S-3 (File No. 333-66015) of Baltimore Gas and Electric Company of our report dated January 19, 2000 relating to the financial statements which appear in this Form 8-K. /s/ PricewaterhouseCoopers LLP - --------------------------------- PricewaterhouseCoopers LLP Baltimore, Maryland February 15, 2000 EX-27.1 5 FINANCIAL DATA SCHEDULE WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CONSTELLATION ENERGY'S DECEMBER 31, 1999 CONSOLIDATED INCOME STATEMENT, BALANCE SHEET AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH STATEMENTS. 1,000,000 12-MOS DEC-31-1999 JAN-01-1999 DEC-31-1999 PER-BOOK 5,523 1,981 1,491 689 0 9,684 1,494 0 1,499 2,993 0 190 2,575 0 0 372 808 0 0 0 2,746 9,684 3,786 186 3,026 3,212 574 7 581 255 260 0 260 251 230 679 1.74 1.74
EX-27.2 6 FINANCIAL DATA SCHEDULE WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM BALTIMORE GAS AND ELECTRIC COMPANY'S DECEMBER 31, 1999 CONSOLIDATED INCOME STATEMENT, BALANCE SHEET AND STATEMENT OF CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH STATEMENTS. 1,000,000 12-MOS DEC-31-1999 JAN-01-1999 DEC-31-1999 PER-BOOK 5,523 414 655 681 0 7,273 1,494 0 861 2,355 0 190 2,206 0 0 129 524 0 0 0 1,869 7,273 3,028 178 2,324 2,502 526 8 534 206 262 13 249 251 174 783
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