-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, bJxicDQoXMIRRq5Sqng9Eyrq+MvMqQ4UbbG3byD1XmtmgvKRlb1nHxIhHq3XvElZ h9MdRH7q0iJoVnxhhkRRUw== 0000912057-94-001171.txt : 19940331 0000912057-94-001171.hdr.sgml : 19940331 ACCESSION NUMBER: 0000912057-94-001171 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 10 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BALTIMORE GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000009466 STANDARD INDUSTRIAL CLASSIFICATION: 4931 IRS NUMBER: 520280210 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-01910 FILM NUMBER: 94519135 BUSINESS ADDRESS: STREET 1: GAS & ELECTRIC BLDG STREET 2: CHARLES CTR CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4107835920 10-K 1 10-K - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K --------------- ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES AND EXCHANGE ACT OF 1934 For the fiscal year ended 1-1910 December 31, 1993 Commission file number
------------------------ BALTIMORE GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) MARYLAND 52-0280210 (State of incorporation) (I.R.S. Employer Identification No.) GAS AND ELECTRIC BUILDING, CHARLES CENTER, 21201 BALTIMORE, MARYLAND (Zip Code) (Address of principal executive offices)
410-783-5920 (Registrant's telephone number, including area code) SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED - ---------------------------------------------------------------------- ----------------------------------- New York Stock Exchange, Inc. Common Stock -- Without Par Value Chicago Stock Exchange, Inc. Pacific Stock Exchange, Inc. Preferred Stock, Series B 4 1/2%, Cumulative, $100 Par Value New York Stock Exchange, Inc. Preferred Stock, Cumulative, $100 Par Value: Series C 4% Series D 5.40% Preference Stock, Cumulative, $100 Par Value: Philadelphia Stock Exchange, Inc. 7.78%, 1973 Series 7.50%, 1986 Series 6.75%, 1987 Series
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: Not Applicable Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes _x_ No __. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. /X/ Aggregate market value of Common Stock, without par value, held by non-affiliates as of February 28, 1994 was approximately $3,395,220,704 based upon New York Stock Exchange composite transaction closing price. COMMON STOCK, WITHOUT PAR VALUE -- 146,446,343 SHARES OUTSTANDING ON FEBRUARY 28, 1994. DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K DOCUMENT INCORPORATED BY REFERENCE - -------------------- ---------------------------------------------------------------------- III Definitive Proxy Statement for the Annual Meeting of Shareholders of Baltimore Gas and Electric Company to be held on April 20, 1994 (Proxy Statement).
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PAGE ---- PART I Item 1 -- Business General...................................... 1 Capital Requirements......................... 2 Rate Matters................................. 3 Nuclear Operations........................... 4 Load Management, Energy, and Capacity Purchases.................................... 5 Fuel for Electric Generation................. 6 Gas Operations............................... 7 Environmental Matters........................ 8 Electric Operating Statistics................ 11 Gas Operating Statistics..................... 12 Franchises................................... 13 Diversified Businesses....................... 13 Employees.................................... 15 Item 2 -- Properties................................... 16 Item 3 -- Legal Proceedings............................ 16 Submission of Matters to a Vote of Security Item 4 -- Holders...................................... 17 Executive Officers of the Registrant (Instruction 3 to Item 401(b) of Regulation Item 10 -- S-K)......................................... 18 PART II Market for Registrant's Common Equity and Item 5 -- Related Stockholder Matters.................. 19 Item 6 -- Selected Financial Data...................... 20 Management's Discussion and Analysis of Financial Condition and Results of Item 7 -- Operations................................... 21 Financial Statements and Supplementary Item 8 -- Data......................................... 29 Changes in and Disagreements with Accountants Item 9 -- on Accounting and Financial Disclosure....... 56 PART III Directors and Executive Officers of the Item 10 -- Registrant................................... 56 Item 11 -- Executive Compensation....................... 56 Security Ownership of Certain Beneficial Item 12 -- Owners and Management........................ 56 Certain Relationships and Related Item 13 -- Transactions................................. 56 PART IV Exhibits, Financial Statement Schedules and Item 14 -- Reports on Form 8-K.......................... 56 Signatures........................................................... 66
PART I ITEM 1. BUSINESS Baltimore Gas and Electric Company and Subsidiaries are herein collectively referred to as the Company. The Company is engaged in utility operations and related businesses through Baltimore Gas and Electric Company (BGE). The Company is engaged in diversified businesses primarily through BGE's wholly owned subsidiary, Constellation Holdings, Inc. and its subsidiaries (collectively, the Constellation Companies). BGE was incorporated under the laws of the State of Maryland on June 20, 1906, and is primarily engaged in the business of producing, purchasing, and selling electricity, and purchasing, transporting, and selling natural gas within the State of Maryland. BGE is qualified to do business in the District of Columbia where its federal affairs office is located. BGE is qualified to do business in the Commonwealth of Pennsylvania where it is participating in the ownership and operation of two electric generating plants as described under ITEM 2. PROPERTIES -- ELECTRIC. BGE also owns two-thirds of the outstanding capital stock, including one-half of the voting securities, of Safe Harbor Water Power Corporation (Safe Harbor), a hydroelectric producer on the Susquehanna River at Safe Harbor, Pennsylvania. (SEE ITEM 2. PROPERTIES -- ELECTRIC.) BNG, Inc. is a wholly owned subsidiary of BGE which invests in natural gas reserves. Other business of BGE includes the sale and service of gas and electric appliances; BGE intends to emphasize this business in the future and will form a subsidiary during 1994 to direct this effort. For financial information by segment of operation see NOTE 2 TO CONSOLIDATED FINANCIAL STATEMENTS. BGE furnishes electric and gas retail services in the City of Baltimore and in all or part of nine counties in Central Maryland. The electric service territory includes an area of approximately 2,300 square miles with an estimated population of 2,602,000. The gas service territory includes an area of approximately 625 square miles with an estimated population of 1,963,000. There are no municipal or cooperative bulk power markets within BGE's service territory. Electric utilities presently face competition in the construction of generating units to meet future load growth and in the sale of electricity in the bulk power markets. On March 25, 1993, the Public Service Commission of Maryland (PSC) issued BGE a Certificate of Public Convenience and Necessity authorizing BGE to construct a 140-megawatt combustion turbine at its Perryman site. The PSC further required BGE to implement a competitive bidding program for the selection of a third-party power supplier for the increment of electric generating capacity needed after the Perryman combustion turbine. BGE announced March 11, 1994 that PECO Energy won the competitive bidding with a proposal to supply 140 megawatts for 25 years beginning June 1, 1997. Electric and gas utilities also face the future prospect of competition for electric and gas sales to retail customers. It is not possible to predict the ultimate effect competition will have on BGE's earnings in future years. As discussed throughout this report, the two units at BGE's Calvert Cliffs Nuclear Power Plant are its principal generating facilities and have the lowest fuel cost in BGE's system. An extended shutdown of either of these Units could have a substantial adverse effect on the Company's business and financial condition. Furthermore, BGE does not consider it possible to obtain insurance adequate to cover all the costs that could result from a major incident or an extended outage at either of the Calvert Cliffs Units. (SEE NUCLEAR OPERATIONS AND NOTE 13 TO CONSOLIDATED FINANCIAL STATEMENTS for information regarding prior outages at the Plant.) The Constellation Companies' businesses are discussed under DIVERSIFIED BUSINESSES on page 13 and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A). The percentages of Operating Revenues and Operating Income attributable to electric, gas, and diversified operations are set forth below:
OPERATING REVENUES OPERATING INCOME* ------------------------- ------------------------- ELECTRIC GAS DIVERSIFIED ELECTRIC GAS DIVERSIFIED ------- -- ---------- ------- -- ---------- 1993..................... 79% 16% 5% 83% 7 % 10% 1992..................... 79 16 5 81 9 10 1991..................... 81 15 4 87 8 5 1990..................... 79 17 4 77 10 13 1989..................... 76 20 4 78 11 11 - -------------------------- *net of income taxes
BGE currently derives approximately 23% of electric revenues and 42% of gas revenues from customers located in the City of Baltimore and 77% and 58%, respectively, from outside the City of Baltimore. No single customer's electric revenues exceed 4% of total electric revenues and no single customer's gas revenues exceed 4% of total gas revenues. 1 The disparity between the percentage of gas operating revenues in relation to the percentage of gas operating income as compared to the same percentages for electric operations is due to BGE's level of investment and its fuel costs in each of these segments. BGE's operating revenue amounts represent recovery of all fuel and operating expenses plus a return on its investment in the business. BGE's net investment for ratemaking purposes in the electric business is $4.5 billion while the comparable investment in its gas business is less than $450 million. Thus, operating revenues include a much greater return component for electric operations than gas operations. Also, as can be seen by referring to ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, CONSOLIDATED STATEMENTS OF INCOME on page 30, gas purchased for resale as a percentage of gas revenues (56%) is greater than electric fuel and purchased energy as a percentage of electric revenues (25%). It should be noted that both purchased gas costs and electric fuel costs are passed through to the customer with no mark-up for profit. The combined effects of these factors yield the observed relationship between operating revenues and income for electric and gas operations. CAPITAL REQUIREMENTS The Company's actual capital requirements for 1991 through 1993, along with estimated amounts for 1994 through 1996, are set forth below:
1991 1992 1993 1994 1995 1996 --------- --------- --------- --------- --------- --------- (IN MILLIONS) Utility Business Construction expenditures (excluding AFC) Electric..................................................... $ 328 $ 292 $ 360 $ 345 $ 319 $ 300 Gas.......................................................... 43 36 51 54 60 56 Common....................................................... 48 39 44 51 46 44 --------- --------- --------- --------- --------- --------- Total construction expenditures.............................. 419 367 455 450 425 400 AFC (a)........................................................ 37 22 23 34 35 25 Deferred nuclear expenditures (b).............................. 23 16 14 12 -- -- Deferred energy conservation expenditures (b).............................................. 3 20 33 48 45 40 Nuclear fuel (uranium purchases and processing charges)........ 2 40 47 42 46 51 Retirement of long-term debt and redemption of preference stock (c)........................................................... 339 486 907 36 281 98 --------- --------- --------- --------- --------- --------- Total utility business......................................... 823 951 1,479 622 832 614 --------- --------- --------- --------- --------- --------- Diversified Businesses........................................... 276 198 300 72 141 97 --------- --------- --------- --------- --------- --------- Total........................................................ $ 1,099 $ 1,149 $ 1,779 $ 694 $ 973 $ 711 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- - -------------------------- (a) Allowance for Funds Used During Construction (AFC) is accrued for all construction projects with a construction period of more than one month beginning January 1, 1992. (SEE NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of AFC.) (b) See NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of deferred nuclear expenditures and deferred energy conservation expenditures. (c) The 1994 amount does not reflect the early redemption of the following bonds: the 7 1/4% Series due April 15, 2001 First Refunding Mortgage Bonds which were redeemed effective March 11, 1994, at 101.88% of principal, and the 7% Series due 1998 First Refunding Mortgage Sinking Fund Bonds which will be redeemed effective April 18, 1994, at 101.11% of principal.
BGE's actual capital requirements may vary from the estimates set forth above because of a number of factors such as inflation, economic conditions, regulation, legislation, load growth, environmental protection standards, and the cost and availability of capital. The Constellation Companies' capital requirements for diversified businesses may vary from the estimates set forth above due to a number of factors including market and economic conditions and are discussed in detail under MD&A -- DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS on page 28. BGE's estimated construction, nuclear fuel, deferred nuclear expenditures, and deferred energy conservation expenditures are expected to amount to approximately $2.1 billion, $250 million, $12 million, and $200 million, respectively, for the five-year period 1994-1998. Electric construction expenditures reflect the installation of two 5,000 kilowatt diesel generators at Calvert Cliffs Nuclear Power Plant, scheduled to be placed in service in 1995; the construction of a 140-megawatt combustion turbine at Perryman, scheduled to be placed in service in 2 1995, which the PSC authorized in an order dated March 25, 1993; and improvements in BGE's existing generating plants and its transmission and distribution facilities. Future electric construction expenditures do not include additional generating units in light of the competitive bidding process established by the PSC as discussed on page 1. The Company estimates currently that expenditures for compliance with the sulfur dioxide provisions of the Clean Air Act of 1990 will total approximately $55 million through 1995. During the period January 1, 1989 through December 31, 1993, BGE expended $2,299 million for gross additions to utility plant or approximately 32% of its total utility plant (exclusive of nuclear fuel) at December 31, 1993. During the same period, a total of $272 million of utility plant was retired. Nuclear fuel expenditures include uranium purchases and processing charges. BGE presently estimates that approximately $750 million will be required for retirements and redemptions of long-term debt (including sinking fund payments) and BGE preference stock during the five-year period 1994-1998. For further information with respect to capital requirements and for a discussion of internal generation of cash, see ITEM 7. MD&A -- LIQUIDITY AND CAPITAL RESOURCES. RATE MATTERS ELECTRIC AND GAS BASE RATE DECISION On April 23, 1993, the PSC issued an Order (the 1993 Rate Order) authorizing BGE annualized electric and gas base rate increases of $84.9 million and $1.6 million, respectively. The increases are equivalent to 4.5% and 0.4% of total electric and gas revenues, respectively. In granting the increases, the PSC provided a return on BGE's higher level of electric and gas rate base and recognized increases in electric operating expenses associated primarily with maintaining and improving system reliability. This was partially offset by a reduction in the authorized rate of return to 9.40% from the 9.94% rate of return previously authorized. The 1993 Rate Order also provided for recovery of one-half of the annual level of the increase in postretirement benefit costs under Statement of Financial Accounting Standards No. 106. The PSC directed BGE to defer the remainder of the annual increase in these costs for inclusion in BGE's next base rate proceeding and provided that costs deferred during the intervening period will be amortized over a fifteen-year period beginning in 1998. ENERGY CONSERVATION SURCHARGE The PSC approved a base rate surcharge effective July 1, 1992 which provides for the recovery of deferred energy conservation expenditures, a return thereon, lost revenues, and incentives for achievement of predetermined goals for certain conservation programs subject to an earnings test. The compensation for foregone sales due to conservation programs and the incentives for achieving conservation goals must be refunded to customers if BGE is earning in excess of its authorized rate of return, as determined by the PSC. (See discussion in ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS.) The surcharge is reset on July 1 of each year. ELECTRIC FUEL RATE PROCEEDINGS By statute, electric fuel costs are recoverable if the PSC finds that BGE demonstrates that, among other things, it has maintained the productive capacity of its generating plants at a reasonable level. The PSC and Maryland's highest appelate court have interpreted this as permitting a subjective evaluation of each unplanned outage at BGE's generating plants to determine whether or not BGE had implemented all reasonable and cost effective maintenance and operating control procedures appropriate for preventing the outage. The PSC has established a Generating Unit Performance Program (GUPP) to measure annual utility compliance with maintaining the productive capacity of generating plants at reasonable levels by establishing a system-wide generating performance target and individual performance targets for each base load generating unit. As a result, actual generating performance, after adjustment for planned outages, is compared to the system-wide target and, if met, should signify compliance with the requirements of Maryland law. Failure to meet the system-wide target will result in review of each unit's adjusted actual generating performance versus its performance target in determining compliance with the law, and the basis for possibly imposing a penalty on BGE. Failure to meet these targets requires BGE to demonstrate that the outages causing the failure are not the result of mismanagement. Parties to fuel rate hearings may still question the prudence of BGE's actions or inactions with respect to any given generating plant outage, which could result in a disallowance of replacement energy costs. BGE is involved in fuel rate proceedings annually where issues concerning individual plant outages can be raised. Recovery of a portion of replacement energy costs has been denied in past proceedings and BGE cannot estimate the amount that could be denied in future fuel rate proceedings, but such amounts could be material. (See NUCLEAR OPERATIONS.) BGE is required to submit to the PSC the actual generating performance data for each calendar year 45 days after year end. The PSC reviews BGE's performance for each calendar year in the first fuel rate proceeding initiated following the submission of the actual generating performance data for that year. BGE must initiate fuel 3 rate proceedings in any month following a month during which the calculated fuel rate decreased by more than 5% and may initiate fuel rate proceedings in any month following a month during which the calculated fuel rate increased by more than 5%. NUCLEAR OPERATIONS Discussed below are certain events relating to the operations of the Calvert Cliffs Nuclear Power Plant (the Plant) during the period 1987 to the present including issues involving the possible disallowance of replacement energy costs incurred during unplanned outages at the Plant. All outstanding issues will be resolved in fuel rate proceedings before the PSC which are conducted in accordance with the procedures outlined above under RATE MATTERS -- ELECTRIC FUEL RATE PROCEEDINGS. OPERATIONS IN 1987 The Plant generated 10,069,576 megawatt hours (MWH) in 1987 which resulted in a capacity factor of 70%. In October 1988, BGE filed a fuel rate application for a change in its electric fuel rate under GUPP, which covered BGE's operating performance in 1987. This was the first proceeding filed under this program and BGE's filing demonstrated that it met the system-wide and individual plant performance targets for 1987, including the performance target for the Plant. BGE believes, therefore, it is entitled to recover all fuel costs incurred in 1987 without any disallowances. However, People's Counsel alleges that a number of the outages at the Plant (including the 66-day outage described below) were due to management imprudence and requests that the PSC disallow recovery of the associated replacement energy costs which BGE estimates to be approximately $33 million. (See NOTE 13 TO CONSOLIDATED FINANCIAL STATEMENTS.) This matter is awaiting a decision by a hearing examiner. In late March, 1987, the Nuclear Regulatory Commission (NRC) conducted an inspection of the Plant for the purpose of examining BGE's compliance with environmental qualification requirements mandated by NRC regulations. These regulations require the establishment of a qualification file for the purpose of demonstrating proof of operability of designated electric equipment regarded as important to safety. This written proof of operability is related to the ability of the equipment to function under harsh environments, such as extreme temperatures, humidity, and radiation. The NRC's inspections revealed cable splices that were lacking required documentation demonstrating compliance with NRC regulations. The inspection results from Unit 2, which was shut down for maintenance and refueling at the time of inspection, indicated a sufficient number of equipment qualification problems that BGE shut down Unit 1 on April 1, 1987, in order to inspect for similar nonqualified electrical connections. Subsequently, BGE identified an additional problem regarding the certification of piping system fasteners with mechanical safety requirements. The fasteners must be certified as meeting specified American Society of Mechanical Engineers requirements; however, BGE was unable to document that all of the fasteners in question had been certified. BGE received a notice of violation from the NRC in connection with the environmental qualifications problem and paid civil penalties in the amount of $300,000. In addition, the Calvert Cliffs Units were out of service for a total of 66 days in order to document compliance with these environmental and mechanical qualification requirements. OPERATIONS IN 1988 The Plant generated 11,733,900 MWH in 1988 which resulted in a capacity factor of 81%. BGE filed a fuel rate application under GUPP in May, 1989 in which it demonstrated that it met the system-wide and individual plant performance targets for 1988. People's Counsel alleged that BGE imprudently managed several outages at the Plant and requested that the PSC disallow recovery of $2 million of replacement energy costs. On November 14, 1991, a Hearing Examiner at the PSC issued a proposed Order, which became final on December 17, 1991 and concluded that no disallowance was warranted. The Hearing Examiner found that BGE maintained the productive capacity of the Plant at a reasonable level, noting that it produced a near record amount of power and exceeded the GUPP standard. Based on this record, the Order concluded there was sufficient cause to excuse any avoidable failures to maintain productive capacity at higher levels. OPERATIONS IN 1989 TO 1991 -- EXTENDED OUTAGE The Plant generated 2,719,197 MWH in 1989 and 1,251,416 MWH in 1990. In the Spring of 1989, a leak was discovered around the Unit 2 pressurizer heater sleeves during a refueling outage. BGE shut down Unit 1 as a precautionary measure on May 6, 1989 to inspect for similar leaks and none were found at that time. However, Unit 1 was out of service for the remainder of 1989 and 285 days of 1990 to undergo maintenance and modification work to enhance the reliability of various safety systems, to repair equipment, and to perform required periodic surveillance tests. Unit 2 remained out of service until May 4, 1991 to complete repair of the pressurizer, perform maintenance and modification work, and complete the refueling. The replacement energy costs associated with these extended outages for both Units at Calvert Cliffs, concluding with the return to service of Unit 2, are estimated to be $458 million. This estimate is based on a computer simulation comparing the actual operating conditions during the extended outages with operating conditions assuming the Plant ran at its targeted capacity factor. 4 The extended outages experienced at the Plant are being reviewed by the PSC in the 1989-1991 fuel rate proceeding, and People's Counsel and others have challenged recovery of some part of the associated replacement energy costs. In the PSC's Rate Order issued in BGE's 1990 Base Rate Case, it found that $4 million of operations and maintenance expenses incurred by BGE during the 1989-1990 outages at the Plant should not be recoverable from customers. The PSC concluded that the related work, which was performed at Unit 1 during the 1989-1990 outage, was avoidable and caused by Company actions which were deficient. The work characterized as avoidable had a significant impact on the duration of the Unit 1 outage. The PSC's Order stated that its conclusions in this proceeding did not have a binding effect in the fuel rate proceeding on the recoverability of Calvert Cliffs' replacement energy costs. However, BGE believes that it is doubtful that the PSC will authorize recovery of the full amount of replacement energy costs presently under investigation. Based on a review of the circumstances surrounding the extended outages by BGE personnel as well as independent consultants, in 1990 BGE recorded a provision of $35 million against the possible disallowance of such costs. However, BGE cannot determine whether replacement energy costs may be disallowed in the 1989-1991 fuel rate proceeding in excess of the provision, but such amounts could be material. On March 15, 1994, the PSC Staff and the Office of People's Counsel filed testimony in the 1989-1991 fuel rate proceedings. The PSC Staff concluded that approximately 46% of the outage time was unreasonably incurred and that approximately $200 million of replacement energy costs should be disallowed. People's Counsel concluded that approximately $400 million of the replacement energy costs should be disallowed. BGE is tentatively scheduled to file rebuttal testimony in mid-August of 1994 at which time it will vigorously contest the findings of Staff and People's Counsel. Further hearings in this matter are not scheduled until mid-year of 1995. As previously reported, in December 1988, the NRC categorized the Plant as one requiring close monitoring and increased NRC attention. The NRC did so following certain events that the NRC indicated raised questions about the effectiveness of past corrective action regarding engineering and technical areas and the overall approach to safety at the Plant. Details of such events were described in the Report on Form 10-K for the year ended December 31, 1990 in the section titled "Nuclear Operations" on pages 4 through 7. In February 1992, the NRC removed the Plant from its list of nuclear plants categorized as requiring close monitoring as a result of improved performance in previously identified problem areas and the demonstration of a sustained period of safe operation. OPERATIONS IN 1991 AFTER THE EXTENDED OUTAGE The Plant generated 9,036,100 MWH in 1991, which resulted in a capacity factor of 63%. BGE filed a fuel rate application under GUPP in June 1992, however, the Hearing Examiner has determined that the 1991 case will not be addressed until the case covering the extended outage has been resolved. OPERATIONS IN 1992 The Plant generated 10,663,950 MWH in 1992, which resulted in a capacity factor of 74%. BGE's fuel rate application under GUPP for 1992 demonstrated that the Plant exceeded its individual plant performance targets and that system-wide performance exceeded targeted levels. There are no contested performance issues based on 1992 performance. OPERATIONS IN 1993 The Plant generated 12,300,816 MWH in 1993, which resulted in a capacity factor of 85%. BGE's fuel rate application under GUPP for 1993 demonstrated that the Plant exceeded its individual plant performance targets and that system-wide performance exceeded targeted levels. LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES BGE has implemented various active load management programs designed to be used when system operating conditions require a reduction in load. These programs include customer-owned generation and curtailable service for large commercial and industrial customers, air conditioning control which is available to residential and commercial customers, and residential water heater control. The load reductions typically have been invoked on peak summer days; the summer peak capacity impact for 1994 from active load management is expected to be approximately 470 megawatts (MW). Cost recovery for these load management programs is attained through the inclusion in rate base of capital investments and the appropriate expenses (including credits on customer bills) for recovery in base rate proceedings. The generating and transmission facilities of BGE are interconnected with those of neighboring utility systems to form the Pennsylvania-New Jersey-Maryland Interconnection (PJM). Under the PJM agreement, the interconnected facilities are used for substantial energy interchange and capacity transactions as well as emergency assistance. In addition, BGE enters into short-term capacity transactions at various times to meet PJM obligations. 5 BGE has an agreement with Pennsylvania Power & Light Company (PP&L) to purchase a mix of energy and capacity from June 1, 1990 through May 31, 2001. This agreement, which has been accepted by the Federal Energy Regulatory Commission, is designed to help maintain adequate reserve margins through this decade and provide flexibility in scheduling power plant additions for the latter half of the 1990s. The PP&L agreement entitles BGE to 5.94% of the energy output, and net capacity (currently 124 MW), of PP&L's nuclear Susquehanna Steam Electric Station from October 1, 1991 to May 31, 2001 and also enables BGE to treat a portion of PP&L's capacity as BGE's capacity for purposes of satisfying BGE's installed capacity requirements as a member of the PJM. BGE is not acquiring an ownership interest in any of PP&L's generating units. PP&L will continue to control, manage, operate, and maintain that station and all other PP&L-owned generating facilities. BGE's firm capacity purchases at December 31, 1993 represented 170 MW of rated capacity of Bethlehem Steel Corporation's Sparrows Point complex, 57 MW of rated capacity of the Baltimore Refuse Energy Systems Company, and 124 MW of base load capacity from PP&L. Also, on March 11, 1994, BGE announced that PECO Energy won a competitive bid for additional capacity with a proposal to supply 140 megawatts for 25 years beginning June 1, 1997. BGE anticipates submitting a contract for approval to the PSC in the Spring of 1994. FUEL FOR ELECTRIC GENERATION Information regarding BGE's electric generation by fuel type and the cost of fuels in the five-year period 1989-1993 is set forth in the following tables:
AVERAGE COST OF FUEL CONSUMED GENERATION BY FUEL TYPE ( CENTS PER MILLION BTU) --------------------------------------------- ---------------------------------------------- 1993 1992 1991 1990 1989 1993 1992 1991 1990 1989 ----- ----- ----- ----- ----- ------ ------ ------ ------ ------ Nuclear (a)................... 43% 40% 33% 5% 10% 53.01 45.54 48.64 54.86 50.43 Coal.......................... 55 54 44 44 46 151.85 154.76 160.74 154.56 154.31 Oil........................... 3 1 5 7 10 253.36 254.19 284.87 319.44 281.54 Hydro & Gas................... 3 3 4 6 5 -- -- -- -- -- ----- ----- ----- ----- ----- 104 98 86 62 71 Interchange/Purchases (b)..... (4) 2 14 38 29 ----- ----- ----- ----- ----- 100% 100% 100% 100% 100% ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- - -------------------------- (a) Nuclear fuel costs provide for disposal costs associated with long-term off-site spent fuel storage and shipping, currently set by law at one mill per kilowatt-hour of nuclear generation (approximately 10 cents per million Btu) and for contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facility. (SEE FUEL FOR ELECTRIC GENERATION -- NUCLEAR.) (b) Net purchases from (sales to) others.
COAL: BGE obtains a large amount of its coal under supply contracts with mining operators. The remainder of its coal requirements are obtained through spot purchases. BGE believes that it will be able to renew such contracts as they expire or enter into similar contractual arrangements with other coal suppliers. BGE's Brandon Shores Units 1 and 2 have a total annual requirement of approximately 3,200,000 tons of coal (combined) with a sulfur content of less than approximately 0.8%. The average delivered costs per ton paid by BGE for Brandon Shores coal for the years 1989 through 1993 were $40.17, $39.00, $39.80, $39.98, and $39.49, respectively. BGE's Crane Units 1 and 2 have a total annual requirement of about 700,000 tons of coal (combined) with a sulfur content of less than approximately 2.4% and a low ash melting temperature. The average delivered costs per ton paid by BGE for coal at Crane for the years 1989 through 1993 were $42.62, $40.45, $38.88, $38.37, and $37.25, respectively. BGE's Wagner Units 2 and 3 have a total annual requirement of approximately 1,000,000 tons of coal (combined) with a sulfur content of no more than 1%. The average delivered costs per ton paid by BGE for coal at Wagner for the years 1989 through 1993 were $41.45, $41.28, $44.49, $43.19, and $40.62, respectively. Coal deliveries to BGE's coal burning facilities are made by rail and barge. The coal used by BGE is produced from mines located in central and northern Appalachia. BGE has a 20.99% undivided interest in the Keystone coal-fired generating plant and a 10.56% undivided interest in the Conemaugh coal-fired generating plant. The bulk of the annual coal requirements for the Keystone plant is under contract from Rochester and Pittsburgh Coal Company. The Conemaugh plant purchases coal from local suppliers on the open market. The average delivered costs per ton for coal for these plants for the years 1989 through 1993 were $33.62, $36.69, $33.07, $31.53, and $32.42, respectively. OIL: Under normal burn practices, BGE's requirements for residual fuel oil amount to approximately 1,000,000 barrels of low-sulfur oil per year. Deliveries of residual fuel oil are made directly into BGE barges from 6 the suppliers' Baltimore Harbor marine terminal for distribution to the various generating plant locations. The average delivered prices per barrel paid by BGE for residual fuel oil for the years 1989 through 1993 were $17.65, $20.24, $15.53, $17.25, and $15.69 respectively. NUCLEAR: The supply of fuel for nuclear generating stations involves the acquisition of uranium concentrates, its conversion to uranium hexafluoride, enrichment of uranium hexafluoride, and the fabrication of nuclear fuel assemblies. Information is set forth below with respect to fuel for Calvert Cliffs Units 1 and 2: Uranium Concentrates: BGE has, either in inventory or under contract, sufficient quantities of uranium concentrates to meet approximately 80% of its requirements through 1997 and approximately 50% of its requirements for 1998. Conversion: BGE has contractual commitments providing for the conversion of uranium concentrates into uranium hexafluoride which will meet 100% of BGE's requirements through 1995 and approximately 40% of its requirements from 1996 through 1998. Enrichment: BGE has a contract with the Department of Energy for the enrichment of 100% of BGE's enrichment requirements through 1995 and 70% of its requirements from 1996 through 1998. Fuel Assembly BGE has contracted for the fabrication of fuel assemblies for Fabrication: reloads it requires through 1996.
Under the Nuclear Waste Policy Act of 1982 (the 1982 Act), spent fuel discharged from nuclear power plants, including Calvert Cliffs, is required to be placed into a federal repository. Such facilities do not currently exist, and, consequently, must be developed and licensed. BGE cannot now predict when such facilities will be available, although the 1982 Act obligates the federal government to accept spent fuel starting in 1998. While BGE cannot now predict what the ultimate cost will be, the 1982 Act assesses a one mill per kilowatt-hour fee on nuclear electricity generated and sold. At anticipated operating levels, it is expected that this fee will be approximately $11 million for Calvert Cliffs each year. The Energy Policy Act of 1992 (the 1992 Act) contains provisions requiring domestic utilities to contribute to a fund for decommissioning and decontaminating the Department of Energy's (DOE) uranium enrichment facilities. These contributions are generally payable over a fifteen-year period with escalation for inflation and are based upon the amount of uranium enriched by DOE for each utility. The 1992 Act provides that these costs are recoverable through utility service rates as a cost of fuel. Information about the cost of decommissioning is discussed in NOTE 1 TO THE CONSOLIDATED FINANCIAL STATEMENTS on page 39 under the heading "UTILITY PLANT, DEPRECIATION AND AMORTIZATION, AND DECOMMISSIONING." Maryland law makes it unlawful to establish within the State a facility for the permanent storage of high-level nuclear waste, unless otherwise expressly required by federal law. BGE has received a license from the NRC to operate its new on-site independent spent fuel storage facility. BGE now has storage capacity at Calvert Cliffs that will accommodate spent fuel from operations through the year 2006. In addition, BGE can expand its temporary storage capacity to meet future requirements until federal storage is available. Expenditures for nuclear fuel are discussed in MD&A -- LIQUIDITY AND CAPITAL RESOURCES on page 28. Capital requirements for nuclear fuel returned to normal levels in 1992. The 1991 level was abnormally low due to the accumulation in inventory of nuclear fuel purchased and processed over the period of extended outages at Calvert Cliffs during 1989-1991. The 1991 level reflects the use of nuclear fuel from such inventoried stocks rather than new purchases. GAS: BGE has a firm natural gas transportation entitlement of 3,500 dekatherms a day to provide ignition and banking at certain power plants. Gas for electric generation is purchased as needed in the spot market using interruptible transportation arrangements. Certain gas fired units can use residual fuel oil as an alternative. GAS OPERATIONS BGE distributes natural gas purchased directly from several producers and marketers. Transportation to BGE's city gate for these purchases is provided by Columbia Gas Transmission Corporation (Columbia), CNG Transmission Corporation (CNG), and Transcontinental Gas Pipe Line Corporation under various transportation agreements. BGE has upstream transportation capacity under contract on Tennessee Gas Pipeline Company, Texas Eastern Transmission Corporation, Columbia Gulf Transmission Company and ANR Pipeline Company (ANR). BGE has storage service agreements with Columbia, CNG and ANR. The transportation and storage agreements are on file with the Federal Energy Regulatory Commission (FERC). 7 BGE's current pipeline firm transportation entitlements to serve its firm loads are 473,597 dekatherms (DTH) per day during the winter period and 291,231 DTH per day during the summer period. BGE uses the firm transportation capacity to move gas from the Gulf of Mexico, Louisiana, south central regions of Texas and Canada to BGE's city gate. The gas is subject to a mix of long and short-term contracts that are managed to provide economic, reliable and flexible service. Additional short-term contracts or exchange agreements with other gas companies can be arranged in the event of short term emergencies. To supplement BGE's gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, BGE has propane air and liquefied natural gas facilities. The liquefied natural gas facility consists of a plant for the liquefaction and storage of natural gas with a storage capacity of 1,000,000 DTH and an installed daily capacity of 281,760 DTH. The propane air facility consists of a plant with a mined cavern and refrigerated storage facilities having a total storage capacity equivalent to 1,000,000 DTH and a daily capacity of 91,600 DTH. BGE has under contract sufficient volumes of propane for the operation of the propane air facility and is capable of liquefying sufficient volumes of natural gas during the summer months for operation of its liquefied natural gas facility during winter periods. BGE offers gas for sale to its residential, commercial and industrial customers on a firm and interruptible basis. BGE also provides its large commercial and industrial customers with a transportation service across its distribution system so that these customers may make direct purchase and transportation arrangements with suppliers and pipelines. A transportation fee is charged by BGE that is equivalent to its operating margin on gas it sells to similar customers for the service from the city gate to the customer's facility. This program enables BGE to maintain throughput at a level which assures that fixed costs are spread over the maximum number of DTH. BGE is authorized by the PSC to provide a balancing service for its transportation customers. Future purchased gas costs are expected to increase due to transition costs incurred by BGE gas pipeline suppliers in implementing FERC Order No. 636. These transition costs, if approved by the PSC and FERC, will be passed on to BGE customers through the purchased gas adjustment clause. ENVIRONMENTAL MATTERS The Company is subject to regulation with regard to air and water quality, waste disposal, and other environmental matters by various federal, state, and local authorities. Certain of these regulations require substantial expenditures for additions to utility plant and the use of more expensive low-sulfur fuels. While the Company cannot now precisely estimate the total effect of existing and future environmental regulations and standards upon its existing and proposed facilities and operations, the necessity for compliance with existing standards and regulations has caused BGE to increase capital expenditures by approximately $223 million during the five-year period 1989-1993. It is estimated that the capital expenditures necessary to comply with such standards and regulations will be approximately $37 million, $15 million, and $21 million for 1994, 1995, and 1996, respectively. AIR: The Federal Clean Air Act (the Act) mandates health and welfare standards for concentrations of air pollutants. The State of Maryland is charged by the Act with the responsibility for setting limits on all major sources of these pollutants in the State so that these standards are not exceeded. Except for Crane Units 1 and 2, BGE's generating units are limited to burning fuel (coal or oil) with sulfur content of 1% or below. All units are limited to emitting particulate matter at or below 0.02 grains per standard cubic foot of exhaust gas for oil fired units and 0.03 grains per standard cubic foot for coal fired units. Brandon Shores, a newer plant, is subject to more stringent standards for sulfur dioxide (1.2 pounds per million Btu), and nitrogen dioxide (0.7 pounds per million Btu). The Crane Units must meet limits of 3.5 pounds per million Btu for sulfur dioxide, which is equivalent to a coal sulfur content of approximately 2.4%. BGE is in compliance with existing air quality regulations. Under a consent order with the Maryland Department of the Environment (MDE) relating to such regulations, BGE is operating two of four units at its Riverside facility at reduced capacity until these units are retired during 1994. The fifth Riverside unit was retired in 1991. The Clean Air Act amendments of 1990 require sulfur dioxide emission reductions at Crane and the jointly owned Conemaugh plant by 1995 and additional controls at other coal plants to be in place by 2000. BGE presently plans to achieve emission reduction at Crane by conversion to low-sulfur coal. The capital costs for equipment changes at the Crane plant are estimated to be approximately $7 million. Scrubbers are being installed at both units of the Conemaugh plant, in which BGE has a 10.56% undivided ownership interest. BGE estimates that its share of the costs of the scrubbers will be approximately $42.7 million. In addition, BGE anticipates incurring other Clean Air Act costs of approximately $10 million for various equipment such as continuous emission monitors and precipitator upgrades by 2000. At this time, plans for complying with nitrogen oxide (NOx) control requirements under the Act are less certain because all implementation regulations have not yet been finalized by the government. It is expected that 8 by the year 2000 these regulations will require additional NOx controls for ozone non-attainment at BGE's generating plants and other BGE facilities. The controls will result in additional expenditures that are difficult to predict prior to the issuance of such regulations. Based on existing and proposed ozone non-attainment regulations, BGE currently estimates that the NOx controls at BGE's generating plants will cost approximately $70 million. BGE is currently unable to predict the cost of compliance with the additional requirements at other BGE facilities. WATER: The discharge of effluents into the navigable waters of the State of Maryland is regulated by the MDE, in accordance with the National Pollutant Discharge Elimination System (NPDES) permit program, established pursuant to the Federal Clean Water Act. At the present time, all of BGE's steam electric generating plants have the required NPDES permits. MDE water quality regulations require, among other things, specifying procedures for determining compliance with State water quality standards. These procedures require extensive studies involving sampling and monitoring of the waters around affected generating plants. Under current regulations, the State of Maryland may require changes in plant operations. At this time BGE is performing studies to determine whether any modifications will be required to comply with these new regulations. WASTE DISPOSAL: The United States Environmental Protection Agency (EPA) has promulgated regulations implementing those portions of the Resource Conservation and Recovery Act which deal with management of hazardous wastes. These regulations, and the Hazardous and Solid Waste Amendments of 1984, designate certain spent materials as hazardous wastes and establish standards and permit requirements for those who generate, transport, store, or dispose of such wastes. The State of Maryland has adopted similar regulations governing the management of hazardous wastes, which closely parallel the federal regulations. BGE has implemented procedures for compliance with all applicable federal and state regulations governing the management of hazardous wastes. Certain high volume utility wastes such as fly ash and bottom ash have been exempted from these regulations. The Company currently utilizes almost all of its coal fly ash and bottom ash as structural fill material in a manner approved by the State of Maryland. The remainder of the coal ash is sold to the construction industry for a number of approved applications. The Federal Comprehensive Environmental Response, Compensation and Liability Act (Superfund statute) establishes liability for the cleanup of hazardous wastes found contaminating the soil, water, or air. Those who generated, transported or deposited the waste at the contaminated site are each jointly and severally liable for the cost of the cleanup, as are the current property owner and their predecessors in title at the time of the contamination. In addition, many states have enacted laws similar to the Superfund statute. On October 16, 1989, the EPA filed a complaint in the U.S. District Court for the District of Maryland under the Superfund statute against BGE and seven other defendants to recover past and future expenditures associated with cleanup of a site located at Kane and Lombard Streets in Baltimore. The State of Maryland intervened by filing a similar complaint in the same case and court on February 12, 1990. The complaints allege that BGE arranged for its fly ash to be deposited on the site. The litigation is currently stayed pending settlement discussions among all parties. Additional investigation was initiated on the remainder of the site by the MDE for the EPA but was never completed. BGE and three other defendants agreed to complete the remedial investigation and feasibility study of groundwater contamination around the site in a July 1993 consent order. The remedial action, if any, for the remainder of the site will not be selected until these investigations are concluded. Therefore, neither the total site cleanup costs, nor BGE's share, can presently be estimated. In the early 1970's, BGE shipped an unknown number of scrapped transformers to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap and storage yard has been found to be contaminated with oil containing high levels of PCBs (PCBs are hazardous chemicals frequently used as a fire-resistant coolant in electrical equipment). On December 7, 1987, the EPA notified BGE and other utilities that they are considered potentially responsible parties (PRPs) with respect to the cleanup of the site. A remedial investigation and feasibility study by BGE and the other PRPs is in progress. The investigation costs are estimated to be about $6 million. BGE's share of the investigation costs is estimated to be approximately 15.8%, or $1 million, based on an allocation formula applied to the PRP group. The total cleanup costs are not yet known so BGE's potential liability cannot be estimated, but such liability could be material. During the early 1970's, BGE disposed of a small amount of low-level nuclear waste at a site in Morehead, Kentucky, known as Maxey Flats. This site was found to have been operated improperly. As a result, low-level radioactive contaminants have been found to be leaking from the site. On November 26, 1986, the EPA notified BGE that it is one of approximately 800 PRPs. A remedial investigation and feasibility study was completed by BGE and other PRPs. The EPA has issued its Record of Decision, recommending a natural stabilization remedy. The cost estimate for this remedy is currently estimated to be approximately $60 million for all PRPs. BGE's 9 volumetric share of the waste on-site is 0.0103 percent of the total, based upon BGE's records of waste shipped to the site compared to the total recorded waste. BGE's potential liability cannot be estimated, but such liability is not likely to be substantial because its volumetric share of the waste on-site is so small. From 1985 until 1989, BGE shipped waste oil and other materials to the Industrial Solvents and Chemical Company in York County, Pennsylvania for disposal. The Pennsylvania Department of Environmental Resources (Pennsylvania Department) subsequently investigated this site and found it to be heavily contaminated by hazardous wastes. The Pennsylvania Department notified BGE on August 15, 1990, that it and approximately 1,000 other entities were PRPs with respect to the cost of all remedial activities to be conducted at the site. No remedial investigation or feasibility study has been undertaken, but the PRPs agreed to perform waste characterization at the site in a July 1993 consent order. Also, the PRPs agreed to remove and dispose of specified numbers of drums and tanks of waste in a December 1993 consent order. BGE's share of the liability at this site currently is estimated to be approximately 2.39%, but this may change as additional information about the site is obtained. The actual cost of remedial activities has not been determined. As a result of these factors, BGE's potential liability cannot presently be estimated. However, such liability could be material. On March 9, 1993 BGE was served in litigation instituted by the EPA in the United States District Court for the Eastern District of Pennsylvania involving contamination of the Douglassville site in Berks County, Pennsylvania. BGE was named as a third party defendant based upon allegations that BGE had contracted with A&A Waste Oils, an original defendant, to dispose of oils and lubricants. BGE was dismissed as a party to this litigation in August, 1993. In the early part of the century, predecessor gas companies (which were later merged into BGE) manufactured coal gas for residential and industrial use. The residue from this manufacturing process was coal tar, previously thought to be harmless but now found to contain a number of chemicals designated by the EPA as hazardous substances. BGE is coordinating an investigation of these former coal gas plant sites, including exploration of corrective action options to remove coal tar, with the MDE. No formal legal proceedings have been instituted with respect to these sites. The technology for cleaning up such sites is still developing, and potential remedies for these sites have not been identified. As explained in NOTE 13 TO THE CONSOLIDATED FINANCIAL STATEMENTS on page 52, a liability of $25.4 million was accrued in 1993 regarding future estimated expenditures at these sites. Any cleanup costs for these sites in excess of the amount accrued, which could be significant in total, cannot presently be estimated. 10 ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------- 1993 1992 1991 1990 1989 ------------- ------------- ------------- ------------- ------------- Electric Output (In Thousands) -- MWH: Generated....................................... 28,907 25,626 22,767 15,193 18,296 Purchased (A)................................... 2,627 4,323 5,522 11,859 8,959 ------------- ------------- ------------- ------------- ------------- Subtotal.................................... 31,534 29,949 28,289 27,052 27,255 Less Interchange Sales.......................... 4,149 3,180 1,167 1,088 595 ------------- ------------- ------------- ------------- ------------- Total Output................................ 27,385 26,769 27,122 25,964 26,660 ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- Power Generated and Purchased at Times of Peak Load (MW) (one hour): Generated by Company............................ 5,245 3,679 4,948 3,032 2,954 Net Purchased (A)............................... 631 1,879 962 2,445 2,350 ------------- ------------- ------------- ------------- ------------- Peak Load (B)................................... 5,876 5,558 5,910 5,477 5,304 ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- Annual System Load Factor (%)..................... 55.2 54.8 52.4 54.1 57.4 Revenues (In Thousands) Residential..................................... $ 931,643 $ 839,954 $ 882,591 $ 718,032 $ 648,883 Commercial...................................... 869,829 842,694 850,038 758,573 668,819 Industrial...................................... 199,042 201,950 212,864 194,951 191,796 ------------- ------------- ------------- ------------- ------------- System Sales.................................... 2,000,514 1,884,598 1,945,493 1,671,556 1,509,498 Interchange Sales............................... 91,543 64,323 23,845 26,629 17,802 Other........................................... 23,098 19,002 25,187 14,268 19,867 ------------- ------------- ------------- ------------- ------------- Total....................................... $ 2,115,155 $ 1,967,923 $ 1,994,525 $ 1,712,453 $ 1,547,167 ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- Sales (In Thousands) -- MWH: Residential..................................... 10,614 9,735 10,097 9,283 9,451 Commercial...................................... 12,395 11,909 11,707 11,352 11,079 Industrial...................................... 3,763 3,663 3,708 3,743 4,261 ------------- ------------- ------------- ------------- ------------- System Sales.................................... 26,772 25,307 25,512 24,378 24,791 Interchange Sales............................... 4,149 3,180 1,166 1,088 595 ------------- ------------- ------------- ------------- ------------- Total....................................... 30,921 28,487 26,678 25,466 25,386 ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- Customers Residential..................................... 968,212 956,570 939,734 930,880 913,910 Commercial...................................... 100,820 99,673 98,254 96,567 95,102 Industrial...................................... 3,800 3,761 3,584 3,526 3,132 ------------- ------------- ------------- ------------- ------------- Total....................................... 1,072,832 1,060,004 1,041,572 1,030,973 1,012,144 ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- Average Cost of Fuel Consumed ( CENTS per million Btu)............................................. 112.77 110.20 127.89 177.00 167.34 ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- ------------- BGE achieved an all-time peak load of 6,038 megawatts on January 19, 1994. - -------------------------- (A) Includes purchases from Safe Harbor Water Power Corporation, a hydroelectric company, of which the Company owns two-thirds of the capital stock. (B) See page 5 for a discussion of active load management programs which may be activated at times of peak load.
In 1993, BGE changed its classification of commercial and industrial customers to present this information on a basis which is more consistent with predominant industry practices. Prior-year amounts have been reclassified to conform to the current year's presentation. 11 GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31, --------------------------------------------------------------- 1993 1992 1991 1990 1989 ----------- ----------- ----------- ----------- ----------- Gas Output (In Thousands) -- DTH: Purchased.................................................. 71,204 70,208 63,159 59,470 70,063 LNG Withdrawn from Storage................................. 725 742 551 333 789 Produced................................................... 259 92 17 5 736 ----------- ----------- ----------- ----------- ----------- Total Output........................................... 72,188 71,042 63,727 59,808 71,588 Delivery Service Gas Delivered (A).............................................. 38,521 41,048 40,503 43,377 44,696 ----------- ----------- ----------- ----------- ----------- Total.................................................. 110,709 112,090 104,230 103,185 116,284 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Peak Day Sendout (DTH)....................................... 657,700 609,200 610,200 653,900 663,200 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Capability on Peak Day (DTH)................................. 847,000 847,000 817,000 853,000 761,000 Revenues (In Thousands) Residential................................................ $ 265,601 $ 242,737 $ 220,653 $ 218,967 $ 242,389 Commercial Excluding Delivery Service............................... 121,832 112,147 96,189 89,573 112,630 Delivery Service......................................... 3,287 3,591 3,031 3,304 4,409 Industrial Excluding Delivery Service............................... 22,250 21,123 14,855 32,439 18,363 Delivery Service......................................... 12,920 14,290 14,288 17,851 22,661 Other...................................................... 9,959 9,049 9,179 11,285 11,349 ----------- ----------- ----------- ----------- ----------- Total.................................................. $ 435,849 $ 402,937 $ 358,195 $ 373,419 $ 411,801 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Sales (In Thousands) -- DTH: Residential................................................ 40,029 39,042 36,519 35,026 39,806 Commercial Excluding Delivery Service............................... 23,830 23,478 20,687 18,164 21,964 Delivery Service......................................... 7,428 7,102 6,433 5,872 5,778 Industrial Excluding Delivery Service............................... 5,298 5,314 3,605 7,305 3,697 Delivery Service......................................... 31,390 33,638 34,240 34,720 39,452 ----------- ----------- ----------- ----------- ----------- Total.................................................. 107,975 108,574 101,484 101,087 110,697 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- Customers Residential................................................ 491,165 486,863 482,085 482,680 482,538 Commercial................................................. 37,518 37,000 36,561 35,953 35,970 Industrial................................................. 1,353 1,412 1,385 1,401 1,398 ----------- ----------- ----------- ----------- ----------- Total.................................................. 530,036 525,275 520,031 520,034 519,726 ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- ----------- BGE achieved an all-time peak day sendout of 762,000 DTH on January 19, 1994. - -------------------------- (A) Represents gas purchased by alternate fuel customers directly from suppliers for which BGE receives a fee for transportation through its system ("delivery service"). (SEE MD&A -- RESULTS OF OPERATIONS.)
In 1993, BGE changed its classification of commercial and industrial customers to present this information on a basis which is more consistent with predominant industry practices. Prior-year amounts have been reclassified to conform to the current year's presentation. 12 FRANCHISES BGE has nonexclusive electric and gas franchises to use streets and other highways which are adequate and sufficient to permit BGE to engage in its present business. All such franchises, other than the gas franchises in Manchester, Hampstead, Perryville, Sykesville, Havre de Grace, and Montgomery and Frederick Counties, are unlimited as to time. The gas franchises for these jurisdictions expire at various times from 1994 to 2020, except for Havre de Grace which has the right, exercisable at twenty-year intervals from 1907, to purchase all of BGE's gas properties in that municipality. Conditions of the franchises are satisfactory. BGE also has rights-of-way to maintain 26-inch natural gas mains across certain Baltimore City owned property (principally parks) which expire in 1999 and 2004, each subject to renewal during the last year thereof for an additional period of 25 years on a fair revaluation of the rights so granted. Conditions of the grants are satisfactory. Franchise provisions relating to rates have been superseded by the Public Service Commission Law of Maryland. DIVERSIFIED BUSINESSES GENERAL Diversified businesses consist of the operations of the Constellation Companies and BNG, Inc. The Constellation Companies' businesses are concentrated in three major areas -- power generation projects, financial investments, and real estate projects (including senior living facilities). A significant portion of the Constellation Companies' activities are conducted through joint ventures in which they hold varying ownership interests. The Constellation Companies hold up to a 50% ownership interest in 24 power generating projects in operation or under construction accounting for $285 million of the Constellation Companies' assets. One of these power generation construction projects is the Puna project, which is discussed on page 14. These projects, all of which either are qualifying facilities under the Public Utility Regulatory Policies Act of 1978 or are otherwise exempt from the Public Utility Holding Company Act of 1935, are of the following types and aggregate generation capacities: coal 160 MW, solar 170 MW, geothermal 121 MW, waste coal 182 MW, wood burning 70 MW, and hydro 30 MW. In addition, another $6 million has been spent on projects in development. The Constellation Companies also participate in the operation and maintenance of 23 power generation projects existing or under construction, 10 of which are projects in which the Constellation Companies hold an ownership interest. Financial investments account for $213 million of the Constellation Companies' assets. These assets include $91 million in internally and externally managed securities portfolios, $83 million in monoline financial guaranty (credit enhancement) companies, and $39 million in tax-oriented transactions. Real estate projects account for $489 million of the Constellation Companies' assets. These projects include raw land, office buildings, retail, and commercial projects, an entertainment, dining, and retail complex in Orlando, Florida, a mixed-use planned unit development, and senior living facilities. The majority of the real estate projects are in the Baltimore-Washington area and have been adversely affected by the depressed real estate and economic market. The Constellation Companies' investment in wholesale power generating projects includes $163 million representing ownership interests in 16 projects which sell electricity in California under Interim Standard Offer No. 4 power purchase agreements. Under these agreements, the properties supply electricity to purchasing utilities at a fixed energy rate for the first ten years of the agreements and at variable energy rates based on the utilities' avoided cost for the remaining term of the agreements. Avoided cost generally represents a utility's next lowest cost generation to service the demands on its system. These power generation projects are scheduled to convert to supplying electricity at avoided cost rates in various years beginning in late 1996 through the end of 2000. As a result of declines in purchasing utilities' avoided costs after these agreements were signed, revenues at these projects based on current avoided cost levels would be substantially lower than revenues presently being realized under the fixed price terms of the agreements. If current avoided cost levels were to continue into 1996 and beyond, the Constellation Companies could experience reduced earnings or incur losses associated with these projects, which could be significant. The Constellation Companies are investigating alternatives for certain of these power generation projects including, but not limited to, repowering the projects to reduce operating costs, renegotiating the power purchase agreements, and selling their ownership interests in the projects. The Company cannot predict the impact these matters may have on the Constellation Companies or the Company, but the impact could be material. The Constellation Companies contributed approximately $12 million, or 4% to the Company's 1993 after-tax earnings, a decrease from the contribution of approximately $15 million in 1992. For additional information about the Constellation Companies, see MD&A -- RESULTS OF OPERATIONS -- DIVERSIFIED BUSINESSES EARNINGS (which includes the Constellation Companies' earnings information broken down by line of business) and MD&A -- LIQUIDITY AND CAPITAL RESOURCES -- DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS. 13 BNG, Inc. is a wholly owned subsidiary of BGE which invests in natural gas reserves. BNG owns gas producing properties in West Virginia, the output of which is sold to BGE for the life of the reserves under a contract on file with the PSC. PUNA PROJECT As discussed in previous filings made by the Company under the Securities Exchange Act of 1934, the Constellation Companies have a 49% ownership interest in a joint venture, Puna Geothermal Venture (PGV). PGV developed and is operating a 25-megawatt geothermal energy project on the island of Hawaii (the Big Island) in the State of Hawaii (the Puna project). Construction of the Puna project was scheduled to be completed during 1991; however, it began generating electricity on April 22, 1993. PGV sells the electricity it generates to Hawaii Electric Light Company, Inc. ("Hawaii Electric") under a power purchase agreement that calls for the supply by PGV of at least 22 megawatts. Through the date of this Report, the Constellation Companies' investment in the Puna project was $81.7 million. In addition, the Constellation Companies have loaned $5 million (including accrued interest) to the other partner in PGV for use in funding venture costs. PGV has outstanding a $93.4 million construction loan. In connection with the construction loan, Constellation Investments, Inc. (CII) provided a guarantee to the lending institution that requires the Constellation Companies to put up to $15 million of equity into the Puna project in certain events. The lender has the right to call the guarantee but has not done so. Negotiations are ongoing with the project lenders to convert the construction loan to permanent financing. The diversified businesses section of the capital requirements chart on page 15 includes $15 million for the year 1994 relating to the Puna project. Of this amount, approximately $14 million is additional equity that the Constellation Companies will be required to contribute to PGV under the CII guarantee, and approximately $1 million is additional costs relating to the project. In addition, the Constellation Companies may need to fund $3 million to $20 million during 1994 that is not included in the capital requirements chart to deal with the problem with the production wells described below. The Company cannot predict the impact that the matters involving the Puna project discussed below may have on the Constellation Companies or the Company, but such impact could be material. PGV currently has two production wells that provide steam to power the project. Recently, one of the production wells changed from a steam dominated resource to a brine dominated resource. The result is that the well produces considerably more fluid to inject back into the ground. If the second production well also changes from steam dominated to brine dominated, PGV will have insufficient injection capacity to handle the resulting increase in fluid volume and this may affect the project's ability to generate the megawatts required under the power purchase agreement. Studies are underway to determine both the likelihood of the second production well changing to brine dominated and the need for additional injection or production wells. The studies have not reached a point where a prediction about the outcome can be made. On April 13, 1993, Hawaii Electric filed suit, HAWAII ELECTRIC LIGHT COMPANY, INC. v. PUNA GEOTHERMAL VENTURE COMPANY, INC., Civil No. 93-234 (3rd Circuit Ct., Hawaii), seeking to require PGV to pay contractual penalties of $7.5 million (for delays in the scheduled delivery of power to Hawaii Electric) and seeking to require PGV to pay consequential damages. PGV asserts that the delay was caused by a "force majeure" event. A tentative settlement has been agreed to which requires no additional capital contributions from the Constellation Companies. PGV intervened in WAO KELE O PUNA, ET AL. v. WAIHEE, ET AL., Civil No. 91-3553-10 (1st Circuit Court, Hawaii) on the grounds that plaintiffs improperly are seeking to include the Puna project in an existing suit against the State of Hawaii and the County regarding an unrelated project. If plaintiffs succeed, the State and the County could be enjoined from any further permit review and issuance and from monitoring activity for the Puna project, effectively shutting down the Puna project. The Constellation Companies understand that the unrelated project has been cancelled, but the effect, if any, on this lawsuit are uncertain. During 1993, EPA informed PGV that it was investigating the circumstances regarding two air releases of hydrogen sulfide from the Puna project's well drilling activities. EPA issued a final preliminary assessment report giving the PGV site a low priority for further assessment action based on the fact there is no residual hydrogen sulfide problem at the site to be remediated. The Constellation Companies' partner in the Puna project continues to experience financial difficulties. The partner has not been meeting its funding obligation to PGV for over two years. Also, the partner is currently in default under the $5 million loan it obtained from the Constellation Companies. On February 22, 1994, the Constellation Companies reached tentative agreement with the partner and certain of the partner's direct and 14 indirect shareholders which would result in recapitalization of the project, and repayment of the $5 million loan to Constellation. This agreement is subject to project lender approval and certain approvals by shareholders of the partner. There are no assurances that these approvals will be obtained. CAPITAL REQUIREMENTS Capital requirements for diversified businesses for 1991 through 1993, along with estimated amounts for 1994 through 1996, are set forth below:
1991 1992 1993 1994 1995 1996 ---- ---- ---- ---- ---- ---- (IN MILLIONS) Retirement of long-term debt......................... $167 $118 $222 $ 9 $ 81 $ 77 Investment requirements....... 109 80 78 63 60 20 ---- ---- ---- ---- ---- ---- Total diversified businesses................. $276 $198 $300 $ 72 $141 $ 97 ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- ----
The investment requirements shown above include the Constellation Companies' portion of equity funding to committed projects under development as well as net loans made to project partnerships. The investment requirements for past periods reflect actual funding of projects, whereas investment requirements for the years 1994-1996 reflect the Constellation Companies' estimate of funding during such periods for ongoing and anticipated projects. Also, guarantees of $36 million may be called which are not included above. For more information see SCHEDULE VII -- GUARANTEES OF SECURITIES OF OTHER ISSUERS. Estimates of the Constellation Companies' investment requirements are subject to continuous review and modification. Actual investment requirements may vary significantly from the amounts above due to the type and number of projects selected for development, the impact of market conditions on those projects, the ability to obtain financing, and the availability of internally generated cash. The Constellation Companies' investment requirements have been met in the past through the internal generation of cash and through borrowings from institutional lenders. See NOTES 3 AND 4 TO CONSOLIDATED FINANCIAL STATEMENTS AND MD&A -- LIQUIDITY AND CAPITAL RESOURCES -- DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS for additional information about diversified activities. EMPLOYEES As of December 31, 1993, BGE employed 9,028 people for its utility operations. Additionally, 135 people were employed by the Constellation Companies. The Constellation Companies' amount excludes the approximately 800 employees at an entertainment, dining, and retail complex in Orlando, Florida and 55 employees of two wholly owned subsidiaries operating two power generation facilities. The number of employees at BGE's utility operations is 7,941 as of the date of this report as a result of the various employee reduction programs initiated in 1993. See NOTE 7 TO CONSOLIDATED FINANCIAL STATEMENTS. 15 ITEM 2. PROPERTIES ELECTRIC: The principal electric generating plants of BGE are as follows:
INSTALLED GENERATION (MWH) CAPACITY ---------------------- PLANT LOCATION (MW) PRIMARY FUEL 1993 1992 - ------------------------ ------------------------ ------------ ------------ ---------- ---------- (AT DECEMBER 31, 1993) Steam Calvert Cliffs Calvert County, MD 1,660 Nuclear 12,300,816 10,663,950 Brandon Shores Anne Arundel County, MD 1,288 Coal 7,584,610 6,793,320 Herbert A. Wagner Anne Arundel County, MD 991 Coal/Oil/Gas 2,953,056 2,348,466 Charles P. Crane Baltimore County, MD 380 Coal 2,102,530 1,818,747 Gould Street Baltimore City, MD 104 Oil 162,160 63,612 Riverside Baltimore County, MD 277 Oil/Gas 81,710 102,215 Westport Baltimore City, MD 127 Oil 33,717 44,332 Jointly Owned -- Steam Keystone Armstrong and Indiana 359(A) Coal 2,497,351 2,500,289 Counties, PA Conemaugh Indiana County, PA 181(A) Coal 1,147,729 1,262,146 Combustion Turbine Notch Cliff Baltimore County, MD 128 Gas 12,276 11,281 Perryman Harford County, MD 208 Oil 11,320 5,320 Westport Baltimore City, MD 121 Gas 9,863 7,905 Riverside Baltimore County, MD 173 Oil/Gas 6,632 2,510 Philadelphia Road Baltimore City, MD 64 Oil 2,537 1,174 Charles P. Crane Baltimore County, MD 14 Oil 386 253 Herbert A. Wagner Anne Arundel County, MD 14 Oil 172 178 ------------ ---------- ---------- Totals 6,089 28,906,865 25,625,698 ------------ ------------ ---------- ---------- ---------- ---------- - ---------------------------------- (A) BGE-owned proportionate interest and entitlement. These totals include diesel capacity of 2 megawatts and 1 megawatt for Keystone and Conemaugh, respectively.
BGE also owns two-thirds of the outstanding capital stock of Safe Harbor Water Power Corporation, and is currently entitled to 277 megawatts of the rated capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under a FERC license which expires in the year 2030. GAS: BGE has propane air and liquefied natural gas facilities as described in Gas Operations on page 7. GENERAL: All of the principal plants and other important units of BGE located in Maryland are held in fee except that several properties (not including any principal electric or gas generating plant or the principal headquarters building owned by BGE in downtown Baltimore) in BGE's service area are held under lease arrangements. The leased spaces are used for various office, service and/or retail merchandising purposes. Electric transmission and electric and gas distribution lines are constructed principally (a) in public streets and highways pursuant to franchises or (b) on permanent fee simple or easement rights-of-way secured for the most part by grants from record owners and as to a relatively small part by condemnation. BGE's undivided interests as a tenant in common in the properties acquired for the Keystone and Conemaugh Plants located in Pennsylvania are held in fee by BGE, subject to minor defects and encumbrances which do not materially interfere with the use of the properties by BGE. All of BGE's property referred to above is subject to the lien of the Mortgage securing BGE's First Refunding Mortgage Bonds. ITEM 3. LEGAL PROCEEDINGS ASBESTOS During 1993, BGE was served in several actions concerning asbestos. The actions are collectively titled IN RE BALTIMORE CITY PERSONAL INJURIES ASBESTOS CASES in the Circuit Court for Baltimore City, Maryland. The actions are based upon the theory of "premises liability," alleging that BGE knew of and exposed individuals to an asbestos hazard. The actions relate to two types of claims. The first type, direct claims by individuals exposed to asbestos, were described in a Report on Form 8-K filed August 20, 1993. BGE and approximately 70 other defendants are involved. The 260 non-employee plaintiffs each claim $6 million in damages ($2 million compensatory and $4 million punitive). BGE does not know the specific facts necessary for BGE to assess its potential liability for these type claims, such as the identity of the BGE facilities at which the plaintiffs allegedly worked as contractors, the names of the plaintiffs' employers, and the date on which the exposure allegedly occurred. 16 The second type are claims by two manufacturers -- Owens Corning Fiberglass and Pittsburgh Corning Corp. -- against BGE and approximately eight others, as third-party defendants. These relate to approximately 1,500 individual plaintiffs who have settled with the manufacturers. BGE does not know the specific facts necessary for BGE to assess its potential liability for these type claims, such as the identity of BGE facilities containing asbestos manufactured by the two manufacturers, the relationship (if any) of each of the individual plaintiffs to BGE, the settlement amounts for any individual plaintiffs who are shown to have had a relationship to BGE, and the dates on which/places at which the exposure allegedly occurred. Until the relevant facts for both type claims are determined, BGE is unable to estimate what its liability, if any, might be. Although insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any ultimate awards in the actions, BGE's potential liability could be material. See ITEM 1. BUSINESS -- RATE MATTERS, NUCLEAR OPERATIONS, ENVIRONMENTAL MATTERS, DIVERSIFIED BUSINESSES -- PUNA PROJECT, and NOTE 13 TO CONSOLIDATED FINANCIAL STATEMENTS. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not Applicable. 17 ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANT Executive Officers of the Registrant are:
OTHER OFFICES OR POSITIONS NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS - ----------------------------- --- --------------------------------------------- --------------------------------------------- Christian H. Poindexter 55 Chairman of the Board (A) Vice Chairman of the Board (Since January 1, 1993) President, Constellation Holdings, Inc. Edward A. Crooke 55 President (B) President, Utility Operations (Since September 1, 1992) Bruce M. Ambler 54 President President, Constellation Constellation Holdings, Inc. Development, Inc. (Since August 1, 1989) Vice President, Constellation Holdings, Inc. George C. Creel 60 Senior Vice President Senior Vice President Generation Vice President, Nuclear Energy (Since January 1, 1993) Vice President, Fossil Energy Thomas F. Brady 44 Vice President Vice President Customer Service and Customer Service and Distribution Accounting (Since July 1, 1993) Vice President, Accounting and Economics Herbert D. Coss, Jr. 59 Vice President Vice President Marketing and Gas Electric Interconnection and Operations Transmission (Since January 1, 1994) Vice President, Interconnection and Operations Vice President, General Services Robert E. Denton 50 Vice President Plant General Manager, Calvert Cliffs Nuclear Energy Nuclear Power Plant (Since September 1, 1992) Manager, Calvert Cliffs Nuclear Power Plant Manager, Quality Assurance and Staff Services Carserlo Doyle 49 Vice President Manager, Telecommunications Electric Interconnection Principal Engineer and Transmission (Since January 1, 1994) Jon M. Files 58 Vice President Vice President, Management and Staff Management Services Services (Since September 1, 1989) Ronald W. Lowman 49 Vice President Manager, Fossil Engineering Fossil Energy Manager, Fossil Engineering (Since January 1, 1993) Services Manager, Generation Maintenance G. Dowell Schwartz, Jr. 57 Vice President Manager, Auditing General Services (since April 1, 1990) Charles W. Shivery 48 Vice President Vice President Finance and Accounting, Corporate Finance, Chief Financial Officer Treasurer and Secretary and Secretary Treasurer and Secretary and (Since July 1, 1993) Manager, Finance Joseph A. Tiernan 55 Vice President Vice President, Corporate Affairs Corporate Administration (Since February 1, 1993) Vice President, Nuclear Energy - -------------------------- (A) Chief Executive Officer, Director, and member of the Executive Committee. (B) Chief Operating Officer, Director, and member of the Executive Committee.
18 Officers of the Registrant are elected by, and hold office at the will of, the Board of Directors and do not serve a "term of office" as such. There is no arrangement or understanding between any officer and any other person pursuant to which the officer was selected. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS STOCK TRADING BGE's Common Stock, which is traded under the ticker symbol BGE, is listed on the New York, Chicago, and Pacific stock exchanges, and has unlisted trading privileges on the Boston, Cincinnati, and Philadelphia exchanges. As of February 28, 1994, there were 82,321 common shareholders of record. DIVIDEND POLICY The Common Stock is entitled to dividends when and as declared by the Board of Directors. There are no limitations in any indenture or other agreements on payment of dividends; however, holders of Preferred Stock (first) and holders of Preference Stock (next) are entitled to receive, when and as declared, from the surplus or net profits, cumulative yearly dividends at the fixed preferential rate specified for each series and no more, payable, quarterly, and to receive when due the applicable Preference Stock redemption payments, before any dividend on the Common Stock shall be paid or set apart. Dividends have been paid on the Common Stock continuously since 1910. Future dividends depend upon future earnings, the financial condition of the Company and other factors. Quarterly dividends were declared on the Common Stock during 1993 and 1992 in the amounts set forth below. COMMON STOCK DIVIDENDS AND PRICE RANGES
1993 1992 ------------------------- ------------------------- PRICE* PRICE* DIVIDEND ---------------- DIVIDEND ---------------- DECLARED HIGH LOW DECLARED HIGH LOW -------- ------- ------- -------- ------- ------- First Quarter................. $ .36 $26 3/8 $22 3/8 $ .35 $23 1/8 $19 3/4 Second Quarter................ .37 26 5/8 23 7/8 .36 22 5/8 19 7/8 Third Quarter................. .37 27 1/2 25 1/8 .36 24 3/8 21 1/2 Fourth Quarter................ .37 26 7/8 23 1/2 .36 24 1/8 21 3/4 -------- -------- Total..................... $ 1.47 $ 1.43 -------- -------- -------- -------- - -------------------------- *Based on New York Stock Exchange Composite Transactions as reported in the eastern edition of THE WALL STREET JOURNAL.
19 ITEM 6. SELECTED FINANCIAL DATA
1993 1992 1991 1990 1989 ---------- ---------- ---------- ---------- ---------- (DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Summary of Operations Total Revenues................................................. $2,668,714 $2,491,343 $2,448,853 $2,178,112 $2,032,009 Expenses Other Than Interest and Income Taxes.................. 2,047,714 1,955,998 1,959,665 1,854,183 1,555,424 ---------- ---------- ---------- ---------- ---------- Income From Operations......................................... 621,000 535,345 489,188 323,929 476,585 Other Income................................................... 15,702 22,096 26,628 36,674 30,928 ---------- ---------- ---------- ---------- ---------- Income Before Interest and Income Taxes........................ 636,702 557,441 515,816 360,603 507,513 Interest Expense............................................... 188,764 189,747 196,588 165,205 149,593 ---------- ---------- ---------- ---------- ---------- Income Before Income Taxes..................................... 447,938 367,694 319,228 195,398 357,920 Income Taxes................................................... 138,072 103,347 85,547 19,952 81,629 ---------- ---------- ---------- ---------- ---------- Income Before Cumulative Effect of Changes in Accounting Methods....................................................... 309,866 264,347 233,681 175,446 276,291 Cumulative Effect of Change in the Method of Accounting for Income Taxes.................................................. -- -- 19,745 -- -- Cumulative Effect of Change in the Method of Accounting for Unbilled Revenues, Net of Taxes............................... -- -- -- 37,754 -- ---------- ---------- ---------- ---------- ---------- Net Income..................................................... 309,866 264,347 253,426 213,200 276,291 Preferred and Preference Stock Dividends....................... 41,839 42,247 42,746 40,261 32,381 ---------- ---------- ---------- ---------- ---------- Earnings Applicable to Common Stock............................ $ 268,027 $ 222,100 $ 210,680 $ 172,939 $ 243,910 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Earnings Per Share of Common Stock Before Cumulative Effect of Changes in Accounting Methods.... $ 1.85 $ 1.63 $ 1.51 $ 1.09 $ 2.03 Cumulative Effect of Change in the Method of Accounting for Income Taxes................................................ -- -- .16 -- -- Cumulative Effect of Change in the Method of Accounting for Unbilled Revenues........................................... -- -- -- .31 -- ---------- ---------- ---------- ---------- ---------- Total Earnings Per Share of Common Stock....................... $ 1.85 $ 1.63 $ 1.67 $ 1.40 $ 2.03 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Dividends Declared Per Share of Common Stock................... $ 1.47 $ 1.43 $ 1.40 $ 1.40 $ 1.38 Ratio of Earnings to Fixed Charges............................. 3.00 2.65 2.27 1.78 3.02 Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends Combined...................................... 2.34 2.08 1.82 1.47 2.44 Financial Statistics at Year End Total Assets................................................... $7,987,039 $7,374,357 $7,137,989 $6,710,375 $5,985,679 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Capitalization Long-term debt............................................... $2,823,144 $2,376,950 $2,390,115 $2,193,844 $2,076,620 Preferred stock.............................................. 59,185 59,185 59,185 59,185 59,185 Redeemable preference stock.................................. 342,500 395,500 398,500 365,000 322,800 Preference stock not subject to mandatory redemption......... 150,000 110,000 110,000 110,000 110,000 Common shareholders equity................................... 2,620,511 2,534,639 2,153,306 2,073,158 2,001,188 ---------- ---------- ---------- ---------- ---------- Total capitalization......................................... $5,995,340 $5,476,274 $5,111,106 $4,801,187 $4,569,793 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Book Value Per Share of Common Stock........................... $ 17.94 $ 17.63 $ 17.00 $ 16.58 $ 16.60 Number of Common Shareholders.................................. 82,287 80,371 71,131 73,049 75,762
20 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS This annual report presents the financial condition and results of operations of Baltimore Gas and Electric Company (BGE) and its subsidiaries (collectively, the Company). Among other information, it provides Consolidated Financial Statements, Notes to Consolidated Financial Statements (Notes), Utility Operating Statistics, and Selected Financial Data. The following discussion explains factors that significantly affect the Company's results of operations, liquidity, and capital resources. RESULTS OF OPERATIONS EARNINGS PER SHARE OF COMMON STOCK Consolidated earnings per share were $1.85 for 1993 and $1.63 for 1992, an increase of $.22 and a decrease of $.04 from prior-year amounts. The changes in earnings per share reflect a higher level of earnings applicable to common stock, offset partially in 1993 and completely in 1992 by the larger number of outstanding common shares. The summary below presents the earnings-per-share amounts.
1993 1992 1991 --------- --------- --------- Utility business........................................................................... $ 1.77 $ 1.52 $ 1.60 Diversified businesses Current-year operations.................................................................. .08 .11 (.09) Cumulative effect of change in the method of accounting for income taxes (see Note 1).... -- -- .16 --------- --------- --------- Total diversified businesses............................................................. .08 .11 .07 --------- --------- --------- Total...................................................................................... $ 1.85 $ 1.63 $ 1.67 --------- --------- --------- --------- --------- ---------
EARNINGS APPLICABLE TO COMMON STOCK Earnings applicable to common stock increased $45.9 million in 1993 and $11.4 million in 1992. The 1993 increase reflects higher utility earnings, slightly offset by lower earnings of diversified businesses. The 1992 increase reflects increases in both utility and diversified businesses earnings. Utility earnings increased in 1993 because BGE sold more electricity than in the previous year and because of increased base rates. Three principal factors produced the increase in sales of electricity: the summer of 1993 was hotter than 1992; commercial customers used more electricity; and the number of residential customers increased. The effect of weather on utility sales is discussed below. The 1993 earnings increases were partially offset by higher operations and maintenance expenses, depreciation expense, and property taxes, and the effect of the Omnibus Budget Reconciliation Act of 1993 (1993 Tax Act), which increased the federal corporate income tax rate to 35% from 34%. Utility earnings increased in 1992 over 1991 because the colder winter in 1992 led to higher electric and gas sales. Operations expenses and interest charges were also lower in 1992, while other income was higher. However, the summer of 1992 was cooler than 1991, and as a result lower electric sales offset a substantial portion of the increase in 1992 utility earnings. The following factors influence BGE's utility operations earnings: regulation by the Public Service Commission of Maryland (PSC), the effect of weather and economic conditions on sales, and competition in the generation and sale of electricity. The base rate increases authorized by the PSC in April 1993 will affect 1994 utility earnings favorably. Several electric fuel rate cases now pending before the PSC discussed in Notes 1 and 13 could also affect future years' earnings. During 1993 and 1992, unfavorable economic conditions diminished electric and gas sales growth in BGE's service territory. Electric utilities presently face competition in the construction of generating units to meet future load growth and in the sale of electricity in the bulk power markets. Electric utilities also face the future prospect of competition for electric sales to retail customers. It is not possible to predict currently the ultimate effect competition will have on BGE's earnings in future years. Earnings from diversified businesses, which primarily represent the operations of Constellation Holdings, Inc. and its subsidiaries (collectively, the Constellation Companies), decreased during 1993 and increased during 1992. The reasons for these changes are discussed in the "Diversified Businesses Earnings" section on pages 26 and 27. EFFECT OF WEATHER ON UTILITY SALES Weather conditions affect BGE's utility sales. BGE measures weather conditions using degree days. A degree day is the difference between the average daily temperature and the baseline temperature of 65 degrees. Hotter weather during the summer, measured by more cooling degree days, results in greater demand for electricity to operate cooling systems. Conversely, cooler weather during the summer, measured by fewer cooling degree days, results in less demand for electricity to operate cooling systems. Colder weather during the winter, as measured by greater heating degree days, results in greater demand for electricity and gas to operate heating systems. 21 Conversely, warmer weather during the winter, measured by fewer heating degree days, results in less demand for electricity and gas to operate heating systems. The degree-days chart below presents information regarding cooling and heating degree days.
30-YEAR 1993 1992 AVERAGE ------------ ------------ ----------- Cooling degree days.................................................................. 865 707 804 Percentage change compared to prior year............................................. 22.3 % (31.1)% Heating degree days.................................................................. 4,959 4,975 4,901 Percentage change compared to prior year............................................. (0.3)% 14.6 %
BGE UTILITY REVENUES AND SALES Electric revenues changed during 1993 and 1992 because of the following factors:
1993 1992 --------- --------- (IN MILLIONS) System sales volumes............................................................................. $ 112.4 $ (32.0) Base rates....................................................................................... 58.5 84.9 Fuel rates....................................................................................... (55.0) (113.8) --------- --------- Revenues from system sales....................................................................... 115.9 (60.9) Interchange sales................................................................................ 27.2 40.5 Other revenues................................................................................... 4.1 (6.2) --------- --------- Total electric revenues.......................................................................... $ 147.2 $ (26.6) --------- --------- --------- ---------
Electric system sales represent volumes sold to customers within BGE's service territory at rates determined by the PSC. These amounts exclude interchange sales, discussed separately later. In 1993, BGE changed its classification of commercial and industrial customers to present this information on a basis which is more consistent with predominant industry practices. Prior-year amounts have been reclassified to conform to the current year's presentation. Below is a comparison of the changes in electric system sales volumes.
1993 1992 ----------- ------------ Residential.......................................................................................... 9.0% (3.6)% Commercial........................................................................................... 4.1 1.7 Industrial........................................................................................... 2.7 (1.2) Total................................................................................................ 5.8 (0.8)
Hotter summer weather was the main reason for the increase in total sales for 1993. The sales increases to residential and commercial customers reflect significantly hotter summer weather, and to a lesser extent, increased usage and customer growth. Sales to industrial customers reflect increased sales of electricity to Bethlehem Steel to support its increased steel production during 1993. Sales to the residential customers decreased in 1992 because of cooler weather in the summer of 1992. This decrease was partially offset by higher sales because of colder winter weather in 1992 and growth in the total number of customers. Improved economic conditions among commercial customers in 1992 increased sales compared to 1991. Sales to industrial customers in 1992 reflect the negative effect of economic conditions on this segment despite higher sales of electricity to Bethlehem Steel after the start-up of its newly modernized hot strip mill. Base rates increased in 1993 for two principal reasons: the PSC's April 1993 rate order and an increased recovery of eligible electric conservation program costs through the energy conservation surcharge. The April 1993 rate order for an annualized electric base rate increase of $84.9 million provided for a higher level of operating expenses and a return on BGE's higher level of electric rate base. The order also reduced the authorized rate of return to 9.40% from the previous rate of 9.94%. Base rates increased in 1992 for similar reasons: the PSC's December 1990 rate order and, to a lesser extent, the recovery of eligible electric conservation program costs through the energy conservation surcharge, which began in July 1992. The December 1990 rate order authorized a $124 million base rate increase to provide rate recognition for BGE's investment and operating expenses at Brandon Shores Unit 2, effective with that Unit's initial commercial operation in May 1991. The order further authorized a $53 million surcharge to base rates in October 1991 to recover certain purchased capacity charges. Although these base rate increases improved BGE's electric revenues during 1992, they had little effect on net income because they were essentially offset by two things: a decrease in the allowance for funds used during construction (AFC) and higher depreciation expense and other taxes because of the completion and commercial operation of Brandon Shores Unit 2; and increased purchased capacity charges. The April 1993 rate order and a continued higher level of recovery of electric conservation program costs under the energy conservation surcharge will favorably affect base rate revenues in 1994. However, if the PSC determines that BGE is earning in excess of its authorized rate of return, BGE will have to refund a portion of 22 energy conservation surcharge revenues to its customers. The portion subject to refund is compensation for foregone sales from conservation programs and incentives for achieving conservation goals. BGE has been earning in excess of its authorized rate of return on electric operations since September 30, 1993. As a result, BGE has deferred the portion of electric energy conservation revenues subject to refund beginning in December 1993. The deferral of these billings is expected to average approximately $1.7 million each month these deferrals continue in 1994. The deferral will continue as long as BGE exceeds its authorized rate of return on electric operations, as determined by the PSC. Changes in fuel rate revenues result from the operation of the electric fuel rate formula. The fuel rate formula is designed to recover the actual cost of fuel, net of revenues from interchange sales (see Notes 1 and 13). Changes in fuel rate revenues and interchange sales normally do not affect earnings. However, if the PSC were to disallow recovery of any part of these costs, earnings would be reduced as discussed in Note 13. Fuel rate revenues decreased during both 1993 and 1992 due to a lower fuel rate. The rate was lower in both years because of a less costly twenty-four month generation mix from greater generation at the Calvert Cliffs Nuclear Power Plant compared to the year before. The 1993 decrease was partially offset by increased electric system sales volumes. The 1992 decrease also reflects $58 million of annual fuel cost savings resulting from the commercial operation of Brandon Shores Unit 2 and the October 1991 expiration of a surcharge to the electric fuel rate. BGE expects electric fuel rate revenues to decrease again in 1994 because of a continued less-costly generation mix. Interchange sales are sales of BGE's energy to the Pennsylvania-New Jersey-Maryland Interconnection (PJM), a regional power pool of eight member companies including BGE. Interchange sales occur after BGE has satisfied the demand for system sales of electricity, if BGE's available generation is the least costly available to PJM utilities. Interchange sales increased during 1993 and 1992 because BGE had a less costly generation mix than other PJM utilities. The less costly mix during 1993 reflects the higher generation levels at the Calvert Cliffs Nuclear Power Plant. The less costly mix during 1992 also reflects the operation of the Calvert Cliffs Nuclear Power Plant and a full year of operation of Brandon Shores Unit 2. Gas revenues increased during 1993 and 1992 because of the following factors:
1993 1992 --------- --------- (IN MILLIONS) Sales volumes........................................................................................ $ 0.6 $ 8.6 Base rates........................................................................................... 2.6 3.3 Gas cost adjustment revenues......................................................................... 28.8 32.9 Other revenues....................................................................................... 0.9 (0.1) --------- --------- Total gas revenues................................................................................... $ 32.9 $ 44.7 --------- --------- --------- ---------
In 1993, BGE changed its classification of commercial and industrial customers to present this information on a basis which is more consistent with predominant industry practices. Prior-year amounts have been reclassified to conform to the current year's presentation. The changes in gas sales volumes compared to the year before were:
1993 1992 ----------- ----------- Residential......................................................................................... 2.5% 6.9% Commercial.......................................................................................... 2.2 12.8 Industrial.......................................................................................... (5.8) 2.9 Total............................................................................................... (0.6) 7.0
Total gas sales decreased during 1993 because of lower sales to industrial customers, partially offset by increased sales to the remainder of the gas-system customers. Sales to industrial customers decreased primarily because of lower use of delivery service gas by Bethlehem Steel and interruptible service customers, who increased their use of alternative fuels. Gas sales to Bethlehem Steel also decreased because of a maintenance outage at its L-Blast furnace. The increases in sales to residential and commercial customers reflect the colder winter weather during the first quarter of 1993 and an increase in the number of customers. Sales to residential and commercial customers during 1992 reflect the colder winter of 1992 and growth in the number of customers. Gas sales to industrial customers for 1992 reflect primarily increased sales volumes to Bethlehem Steel because of higher use of gas in its production and processing. Base rates increased in 1993 for two principal reasons: the PSC's April 1993 rate order and an increased recovery of eligible gas conservation program costs through the energy conservation surcharge. The April 1993 rate order for an annualized gas base rate increase of $1.6 million provided for a higher level of operating expenses and a return on BGE's higher level of gas rate base. The increased base rates during 1992 represent the 23 effects of the PSC's October 1991 rate order. That order authorized a $4 million annualized increase in gas base rate revenues. The April 1993 gas base rate order and continued recovery of gas conservation program costs under the energy conservation surcharge will favorably affect base rate revenues in 1994. Changes in gas cost adjustment revenues result from the operation of the purchased gas adjustment (PGA) clause, which is designed to recover actual gas costs incurred (See Note 1). Changes in gas cost adjustment revenues normally do not affect earnings. Gas cost adjustment revenues increased during both years primarily because of increased prices to recover higher costs of purchased gas and higher sales volumes subject to the PGA clause. Delivery service sales volumes are not subject to the PGA clause because these customers purchase their gas directly from third parties. BGE UTILITY FUEL AND ENERGY EXPENSES Electric fuel and purchased energy expenses were as follows:
1993 1992 1991 --------- --------- --------- (IN MILLIONS) Actual costs........................................................................... $ 483.9 $ 445.2 $ 492.6 Net recovery of costs under electric fuel rate clause (see Note 1)..................... 50.7 111.0 105.6 --------- --------- --------- Total expense.......................................................................... $ 534.6 $ 556.2 $ 598.2 --------- --------- --------- --------- --------- ---------
Actual electric fuel and purchased energy costs during 1993 increased for two principal reasons: a higher net output of electricity generated to meet the demand of BGE's system and the PJM system, and higher purchased capacity costs under the Pennsylvania Power & Light Company Energy and Capacity Purchase Agreement. Actual electric fuel and purchased energy costs decreased during 1992 because of a less costly generation mix. The cost of the generation mix decreased because of the Calvert Cliffs Nuclear Power Plant's return to operation following the completion of extended maintenance and repair outages and the May 1991 commercial operation of Brandon Shores Unit 2. This decrease was partially offset by purchased capacity charges beginning in October 1991 under the Pennsylvania Power & Light Company Energy and Capacity Purchase Agreement. Purchased gas expenses were as follows:
1993 1992 1991 --------- --------- --------- (IN MILLIONS) Actual costs........................................................................... $ 246.4 $ 213.6 $ 185.1 Net (deferral) recovery of costs under purchased gas adjustment clause (see Note 1).... (3.7) 0.5 (3.6) --------- --------- --------- Total expense.......................................................................... $ 242.7 $ 214.1 $ 181.5 --------- --------- --------- --------- --------- ---------
Actual purchased gas costs went up in both 1993 and 1992 for three principal reasons: higher gas prices caused by market conditions; higher reservation charges; and higher output to meet greater demand for BGE gas. Purchased gas costs exclude gas purchased by delivery service customers, including Bethlehem Steel, who obtain gas directly from third parties. Future purchased gas costs are expected to increase due to transition costs incurred by BGE gas pipeline suppliers in implementing Federal Energy Regulatory Commission (FERC) Order No. 636. These transition costs, if approved by FERC, will be passed on to BGE customers through the purchased gas adjustment clause. OTHER OPERATING EXPENSES Operations expense increased during 1993 by $50.6 million. The combined effect of higher labor costs, employee reduction expenses (discussed below), amortization of energy conservation program costs, postretirement benefit expenses resulting from the implementation of Statement of Financial Accounting Standards No. 106 (see Note 6), and nuclear operating costs was in total $70.2 million higher compared to 1992. These increases were partially offset by the 1993 reversal of a $9.8 million charge originally recorded in 1992 for termination benefits associated with the Company's 1992 Voluntary Special Early Retirement Program (1992 VSERP) to reflect the ratemaking treatment adopted by the PSC in its April 1993 rate order. In accordance with that order, the Company has deferred this charge and is amortizing it over a five-year period, beginning in May 1993. Operations expense decreased in 1992 because of lower nuclear contractor costs and lower payroll costs attributable to labor savings from the Company's 1992 VSERP and other cost-control measures. These decreased costs were partially offset by the original charge to operations for the $9.8 million cost of termination benefits associated with the 1992 VSERP and by higher fringe-benefit costs. The Company announced several employee reduction programs during the third quarter of 1993 in conjunction with its ongoing cost control efforts. The cost of these programs totaled $105.5 million (see Note 7). Consistent with previous rate actions of the PSC, BGE has deferred and will amortize the $88.3 million of 1993 Voluntary Special Early Retirement Program (1993 VSERP) costs related to regulated activities over a five-year 24 period beginning in February 1994 . The remaining $17.2 million of these program costs was charged to expense in 1993. Operations expense is expected to be reduced in 1994 by three factors: cost savings from the 1993 employee reduction programs are expected to be realized beginning in 1994; 1993 operations expense reflects the portion of the cost of employee reduction programs charged to expense; and the expected reduction in 1994 operations expense resulting from the sale of a significant portion of the Constellation Companies' investment in senior living facilities (see page 26 for a discussion of the sale of senior living facilities). These decreases will be partially offset by the amortization of the deferred VSERP costs and other increases in operations expenses. Maintenance expense increased in 1993 because of higher labor costs and higher costs at the Calvert Cliffs Nuclear Power Plant. Maintenance expense was essentially unchanged in 1992 because lower costs at certain fossil-fuel electric generating plants were offset by higher costs at Calvert Cliffs. Depreciation expense increased during 1993 and 1992 compared to the year before because of higher depreciable plant in service. The increase during 1993 resulted from the addition of electric transmission and distribution plant and certain capital additions at the Calvert Cliffs Nuclear Power Plant. The 1992 increase resulted from the addition of Brandon Shores Unit 2, which began commercial operation in May 1991. Taxes other than income taxes increased during both years because of higher property taxes from the addition of Brandon Shores Unit 2 to the taxable base effective July 1, 1992. The increase during 1993 also reflects higher franchise taxes because of the increase in total electric and gas revenues and increased payroll taxes. Inflation affects the Company through increased operating expenses and higher replacement costs for utility plant assets. Although timely rate increases can lessen the effects of inflation, the regulatory process imposes a time lag which can delay BGE's recovery of increased costs. There is a regulatory lag primarily because rate increases are based on historical costs rather than projected costs. The PSC has historically allowed recovery of the cost of replacing plant assets, together with the opportunity to earn a fair return on BGE's investment, beginning at the time of replacement. OTHER INCOME AND EXPENSES AFC was essentially unchanged in 1993 because the accrual of AFC on a higher level of construction work in progress compared to 1992 was offset by the lower AFC rate approved in the April 1993 PSC rate order. AFC decreased during 1992 because of the completion and commercial operation of Brandon Shores Unit 2, partially offset by the effects of the expansion of the AFC policy as discussed in Note 1. Interest charges increased slightly in 1993 as a higher level of outstanding debt was partially offset by a decline in the level of interest rates and the redemption of higher coupon debt of BGE. Interest charges decreased during 1992 primarily because of lower levels of debt outstanding and a decline in the level of interest rates. The decreased debt levels in 1992 are attributable to the additional shares of common stock issued and the recovery of previously deferred electric fuel costs. Capitalized interest increased during 1993 because BGE began accruing carrying charges on electric deferred fuel costs excluded from rate base (see Note 5). 1992 capitalized interest decreased because the Constellation Companies discontinued interest capitalization at certain real estate projects. Income tax expense increased during both years because of higher pre-tax earnings. The 1993 increase also reflects the effect of the 1993 Tax Act, which increased the federal corporate income tax rate to 35% from 34%, retroactive to January 1, 1993. As a result, income tax expense related to 1993 operations increased by $4.6 million, and the Company's deferred income tax liability increased by $20.1 million. The Company deferred $12.8 million of the increase in the deferred income tax liability applicable to utility operations for recovery through future rates and charged the remaining $7.3 million to income tax expense. Of this $7.3 million charged to expense, $5.8 million pertains to the Constellation Companies as discussed on page 27. 25 DIVERSIFIED BUSINESSES EARNINGS Earnings per share from diversified businesses were:
1993 1992 1991 --------- --------- --------- Power generation systems..................................................................... $ .07 $ .08 $ .03 Financial investments........................................................................ .10 .09 .01 Real estate development and senior living facilities......................................... (.04) (.05) (.11) Effect of 1993 Tax Act....................................................................... (.04) -- -- Other........................................................................................ (.01) (.01) (.02) --------- --------- --------- Current-year operations...................................................................... .08 .11 (.09) Cumulative effect of change in the method of accounting for income taxes (see Note 1)........ -- -- .16 --------- --------- --------- Total diversified businesses................................................................. $ .08 $ .11 $ .07 --------- --------- --------- --------- --------- ---------
The Constellation Companies' power generation systems business includes the development, ownership, management, and operation of wholesale power generating projects in which the Constellation Companies hold ownership interests, as well as the provision of services to power generation projects under operation and maintenance contracts. Power generation systems earnings during 1993 were flat compared to 1992. The recognition of $8 million of energy tax credits on the commercial operation of the Puna geothermal plant was offset by costs incurred at the Panther Creek waste-coal project in order to resolve fuel quality and other start-up problems. Additionally, 1992 earnings reflect the gain on the partial sale of an ownership interest in a power generation project, representing most of the increase in power generation systems earnings compared to 1991. The Constellation Companies' investment in wholesale power generating projects includes $163 million representing ownership interests in 16 projects which sell electricity in California under Interim Standard Offer No. 4 power purchase agreements. Under these agreements, the projects supply electricity to purchasing utilities at a fixed energy rate for the first ten years of the agreements and at variable energy rates based on the utilities' avoided cost for the remaining term of the agreements. Avoided cost generally represents a utility's next lowest cost generation to service the demands on its system. These power generation projects are scheduled to convert to supplying electricity at avoided cost rates in various years beginning in late 1996 through the end of 2000. As a result of declines in purchasing utilities' avoided costs after these agreements were signed, revenues at these projects based on current avoided cost levels would be substantially lower than revenues presently being realized under the fixed price terms of the agreements. If current avoided cost levels were to continue into 1996 and beyond, the Constellation Companies could experience reduced earnings or incur losses associated with these projects, which could be significant. The Constellation Companies are investigating alternatives for certain of these power generation projects including, but not limited to, repowering the projects to reduce operating costs, renegotiating the power purchase agreements, and selling their ownership interests in the projects. The Company cannot predict the impact these matters may have on the Constellation Companies or the Company, but the impact could be material. Earnings from the Constellation Companies' portfolio of financial investments include capital gains and losses, dividends, income from financial limited partnerships, and income from financial guaranty insurance companies. 1993 financial investment earnings increased slightly over 1992. $6.1 million in income from an investment in a financial guaranty insurance company was substantially offset by lower investment income compared to 1992, resulting from the decline in the size of the investment portfolio due to the sale of selected assets to provide liquidity for ongoing businesses of the Constellation Companies. Financial investment earnings increased in 1992 primarily because of write-downs taken on certain investments in 1991 and because of an improvement in the performance of certain financial limited partnerships. The Constellation Companies' real estate development business includes land under development; office buildings; retail projects; commercial projects; an entertainment, dining and retail complex in Orlando, Florida; a mixed-use planned-unit-development; and senior living facilities. The majority of these projects are in the Baltimore-Washington corridor. They have been affected adversely by the depressed real estate market and economic conditions, resulting in reduced demand for the purchase or lease of available land, office, and retail space. Earnings from real estate development and senior living facilities were essentially unchanged in 1993 compared to 1992 because a $2.1 million gain on the sale of the nursing home portion of the Constellation Companies' investment in senior living facilities was offset by greater operating losses at other real estate projects. The senior living facilities which were sold contributed real estate revenues and operating expenses of approximately $17 million and $16 million, respectively, in 1993. The increase in earnings in 1992 reflects the 1991 write-downs recorded by the Constellation Companies aggregating $10 million on certain real estate 26 projects and a $3.6 million reserve for loans where the value of the collateral was less than the outstanding loan balances. Additionally, the Constellation Companies' real estate portfolio has experienced continuing carrying costs and depreciation and, during 1991, the Constellation Companies began expensing rather than capitalizing interest on certain undeveloped land where development activities were at minimal levels. These factors have affected earnings negatively during 1993 and 1992 and are expected to continue to do so until current market conditions improve. Cash flow from real estate operations has been insufficient to cover the debt service requirements of certain of these projects. Resulting cash shortfalls have been satisfied through cash infusions from Constellation Holdings, Inc., which obtained the funds through a combination of cash flow generated by other Constellation Companies and its corporate borrowings. Until the real estate market shows sustained improvement, earnings from real estate activities are expected to remain depressed. The Constellation Companies' continued investment in real estate projects is a function of market demand, interest rates, credit availability, and the strength of the economy in general. The Constellation Companies' Management believes that although the real estate market is beginning to show signs of improvement, until the economy reflects sustained growth and the excess inventory in the market in the Baltimore-Washington corridor goes down, real estate values will not improve significantly. If the Constellation Companies were to sell their real estate projects in the current depressed market, losses would occur in amounts difficult to determine. Depending upon market conditions, future sales could also result in losses. In addition, were the Constellation Companies to change their intent about any project from an intent to hold until market conditions improve to an intent to sell, applicable accounting rules would require a write-down of the project to market value at the time of such change in intent if market value is below book value. The Effect of the 1993 Tax Act represents a $5.8 million charge to income tax expense to reflect the increase in the Constellation Companies' deferred income tax liability because of the increase in the federal corporate tax rate. ENVIRONMENTAL MATTERS The Company is subject to increasingly stringent federal, state, and local laws and regulations relating to improving or maintaining the quality of the environment. These laws and regulations require the Company to remove or remedy the effect on the environment of the disposal or release of specified substances at ongoing and former operating sites, including Environmental Protection Agency Superfund sites. Details regarding these matters, including financial information, are presented in Note 13 and in Item 1. Business -- Environmental Matters. LIQUIDITY AND CAPITAL RESOURCES CAPITAL REQUIREMENTS The Company's capital requirements reflect the capital-intensive nature of the utility business. Actual capital requirements for the years 1991 through 1993, along with estimated amounts for the years 1994 through 1996, are reflected below.
1991 1992 1993 1994 1995 1996 --------- --------- --------- --------- --------- --------- (IN MILLIONS) Utility Business: Construction expenditures (excluding AFC) Electric................................................ $ 328 $ 292 $ 360 $ 345 $ 319 $ 300 Gas..................................................... 43 36 51 54 60 56 Common.................................................. 48 39 44 51 46 44 --------- --------- --------- --------- --------- --------- Total construction expenditures......................... 419 367 455 450 425 400 AFC....................................................... 37 22 23 34 35 25 Deferred nuclear expenditures............................. 23 16 14 12 -- -- Deferred energy conservation expenditures................. 3 20 33 48 45 40 Nuclear fuel (uranium purchases and processing charges)... 2 40 47 42 46 51 Retirement of long-term debt and redemption of preference stock.................................................... 339 486 907 36 281 98 --------- --------- --------- --------- --------- --------- Total utility business.................................... 823 951 1,479 622 832 614 --------- --------- --------- --------- --------- --------- Diversified Businesses: Retirement of long-term debt.............................. 167 118 222 9 81 77 Investment requirements................................... 109 80 78 63 60 20 --------- --------- --------- --------- --------- --------- Total diversified businesses.............................. 276 198 300 72 141 97 --------- --------- --------- --------- --------- --------- Total....................................................... $ 1,099 $ 1,149 $ 1,779 $ 694 $ 973 $ 711 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- ---------
27 BGE UTILITY CAPITAL REQUIREMENTS BGE's construction program is subject to continuous review and modification, and actual expenditures may vary from the estimates on page 27. Electric construction expenditures include the installation of two 5,000 kilowatt diesel generators at the Calvert Cliffs Nuclear Power Plant, scheduled to be placed in service in 1995; the construction of a 140-megawatt combustion turbine at Perryman, scheduled to be placed in service in 1995, which the PSC authorized in an order dated March 25, 1993; and improvements in BGE's existing generating plants and its transmission and distribution facilities. Future electric construction expenditures do not include additional generating units in light of the competitive bidding process established by the PSC. The Company estimates currently that expenditures for compliance with the sulfur dioxide provisions of the Clean Air Act of 1990 will total approximately $55 million through 1995. During 1993, 1992, and 1991, the internal generation of cash from utility operations provided 71%, 81%, and 74% respectively, of the funds required for BGE's capital requirements exclusive of retirements and redemptions of debt and preference stock. During the three-year period 1994 through 1996, BGE expects to provide through utility operations approximately 70% of the funds required for BGE's capital requirements, exclusive of retirements and redemptions. Utility capital requirements not met through the internal generation of cash are met through the issuance of debt and equity securities. During the three-year period ended December 31, 1993, BGE's issuances of long-term debt, preference stock, and common stock were $1,733 million, $165 million, and $446 million, respectively. During the same period, retirements and redemptions of BGE's long-term debt and preference stock totaled $1,546 million and $167 million, respectively, exclusive of any redemption premiums. The increase in issuances and retirements of long-term debt during 1993 reflects the refinancing of a significant portion of BGE's debt in order to take advantage of the favorable interest rate market. The amount and timing of future issuances and redemptions will depend upon market conditions and BGE's actual capital requirements. The Constellation Companies' capital requirements are discussed below in the section titled "Diversified Businesses Capital Requirements -- Debt and Liquidity." The Constellation Companies plan to meet their capital requirements with a combination of debt and internal generation of cash from their operations. Additionally, from time to time, BGE may make loans to Constellation Holdings, Inc., or contribute equity to Constellation Holdings, Inc. DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS DEBT AND LIQUIDITY. During 1993, Constellation Holdings, Inc. (CHI) closed two private placements totaling $225 million of unsecured serial notes with several institutional investors. CHI used proceeds of the private placements to pay off its bank debt facility, which CHI elected to terminate, as well as for other general corporate uses. In addition, CHI entered into a $20 million unsecured revolving credit facility with a bank on September 30, 1993. This facility matures September 29, 1994 and will be used to provide liquidity for general corporate purposes. As of December 31, 1993, CHI had no borrowings under this facility. The Constellation Companies intend to meet capital requirements by refinancing debt as it comes due and through internally generated cash. These sources include cash that may be generated from operations, the sale of assets, and cash generated by tax benefits earned by the Constellation Companies. In the event the Constellation Companies can obtain reasonable value for real estate properties, additional cash may become available through the sale of projects (for additional information see the discussion of the real estate business and market on page 26 under the heading "Diversified Businesses Earnings"). The ability of the Constellation Companies to sell or liquidate assets described above will depend on market conditions, and no assurances can be given that such sales or liquidations can be made. Also, to provide additional liquidity to meet interim financial needs, CHI may enter into additional credit facilities. INVESTMENT REQUIREMENTS. The investment requirements of the Constellation Companies include its portion of equity funding to committed projects under development, as well as net loans made to project partnerships. Investment requirements for the years 1994 through 1996 reflect the Constellation Companies' estimate of funding for ongoing and anticipated projects and are subject to continuous review and modification. Actual investment requirements may vary significantly from the estimates on page 27 because of the type and number of projects selected for development, the impact of market conditions on those projects, the ability to obtain financing, and the availability of internally generated cash. The Constellation Companies have met their investment requirements in the past through the internal generation of cash and through borrowings from banks and institutional lenders. 28 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA REPORT OF INDEPENDENT AUDITORS To the Shareholders of Baltimore Gas and Electric Company We have audited the accompanying consolidated balance sheets and statements of capitalization of Baltimore Gas and Electric Company and Subsidiaries at December 31, 1993 and 1992, and the related consolidated statements of income, cash flows, common shareholders' equity, and income taxes for each of the three years in the period ended December 31, 1993, and the consolidated financial statement schedules listed in Item 14(a)(1) and (2) of this Form 10-K. These financial statements and financial statement schedules are the responsibility of the Company's Management. Our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by Management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Baltimore Gas and Electric Company and Subsidiaries at December 31, 1993 and 1992, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. In addition, the consolidated financial schedules referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein. As discussed in Note 13 to the consolidated financial statements, the Public Service Commission of Maryland is currently reviewing the replacement energy costs resulting from the outages at the Company's nuclear power plant and the Company provided a reserve of $35 million in 1990 for the possible disallowance of replacement energy costs. The ultimate outcome of the fuel rate proceedings, however, cannot be determined but may result in a disallowance in excess of the reserve provided. As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for income taxes in 1991. We have also previously audited, in accordance with generally accepted standards, the balance sheets and statements of capitalization at December 31, 1991, 1990 and 1989, and the related statements of income, retained earnings, changes in financial position, and income taxes for each of the two years in the period ended December 31, 1990 (none of which are presented herein); and we expressed unqualified opinions on those financial statements. In our opinion, the information set forth in the Summary of Operations included in the Selected Financial Data for each of the five years in the period ended December 31, 1993, appearing on page 20 is fairly stated in all material respects in relation to the financial statements from which it has been derived. /s/ Coopers & Lybrand -------------------------------------- COOPERS & LYBRAND Baltimore, Maryland January 21, 1994 29 CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, ------------------------------------------- 1993 1992 1991 ------------- ------------- ------------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues Electric......................................................................... $ 2,115,155 $ 1,967,923 $ 1,994,525 Gas.............................................................................. 435,849 402,937 358,195 Diversified businesses........................................................... 117,710 120,483 96,133 ------------- ------------- ------------- Total revenues................................................................... 2,668,714 2,491,343 2,448,853 ------------- ------------- ------------- Expenses Other Than Interest and Income Taxes Electric fuel and purchased energy............................................... 534,628 556,184 598,208 Gas purchased for resale......................................................... 242,685 214,103 181,455 Operations....................................................................... 657,110 606,498 634,309 Maintenance...................................................................... 181,685 172,726 173,648 Depreciation..................................................................... 236,774 223,483 201,264 Taxes other than income taxes.................................................... 194,832 183,004 170,781 ------------- ------------- ------------- Total expenses other than interest and income taxes.............................. 2,047,714 1,955,998 1,959,665 ------------- ------------- ------------- Income from Operations............................................................. 621,000 535,345 489,188 ------------- ------------- ------------- Other Income Allowance for equity funds used during construction.............................. 14,492 13,892 23,596 Equity in earnings of Safe Harbor Water Power Corporation........................ 4,243 4,267 4,388 Net other income and deductions.................................................. (3,033) 3,937 (1,356) ------------- ------------- ------------- Total other income............................................................... 15,702 22,096 26,628 ------------- ------------- ------------- Income Before Interest and Income Taxes............................................ 636,702 557,441 515,816 ------------- ------------- ------------- Interest Expense Interest charges................................................................. 212,971 211,712 231,411 Capitalized interest............................................................. (16,167) (13,800) (20,953) Allowance for borrowed funds used during construction............................ (8,040) (8,165) (13,870) ------------- ------------- ------------- Net interest expense............................................................. 188,764 189,747 196,588 ------------- ------------- ------------- Income Before Income Taxes......................................................... 447,938 367,694 319,228 Income Taxes....................................................................... 138,072 103,347 85,547 ------------- ------------- ------------- Income Before Cumulative Effect of Change in Accounting Method..................... 309,866 264,347 233,681 Cumulative Effect of Change in the Method of Accounting for Income Taxes (See Note 1)................................................................................ -- -- 19,745 ------------- ------------- ------------- Net Income......................................................................... 309,866 264,347 253,426 Preferred and Preference Stock Dividends........................................... 41,839 42,247 42,746 ------------- ------------- ------------- Earnings Applicable to Common Stock................................................ $ 268,027 $ 222,100 $ 210,680 ------------- ------------- ------------- ------------- ------------- ------------- Average Shares of Common Stock Outstanding......................................... 145,072 136,248 126,093 Earnings Per Share of Common Stock Before cumulative effect of change in accounting method.......................... $ 1.85 $ 1.63 $ 1.51 Cumulative effect of change in the method of accounting for income taxes......... -- -- .16 ------------- ------------- ------------- Total earnings per share of common stock......................................... $ 1.85 $ 1.63 $ 1.67 ------------- ------------- ------------- ------------- ------------- -------------
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation. 30 CONSOLIDATED BALANCE SHEETS
AT DECEMBER 31, ---------------------------- 1993 1992 ------------- ------------- (IN THOUSANDS) ASSETS Current Assets Cash and cash equivalents...................................................................... $ 84,236 $ 27,122 Accounts receivable (net of allowance for uncollectibles)...................................... 401,853 369,144 Fuel stocks.................................................................................... 70,233 85,063 Materials and supplies......................................................................... 145,130 141,611 Prepaid taxes other than income taxes.......................................................... 54,237 54,510 Other.......................................................................................... 38,971 29,604 ------------- ------------- Total current assets........................................................................... 794,660 707,054 ------------- ------------- Investments and Other Assets Real estate projects........................................................................... 487,397 462,042 Power generation systems....................................................................... 298,514 259,996 Financial investments.......................................................................... 213,315 207,011 Nuclear decommissioning trust fund............................................................. 56,207 43,118 Safe Harbor Water Power Corporation............................................................ 34,138 34,176 Senior living facilities....................................................................... 2,005 24,538 Other.......................................................................................... 65,355 64,986 ------------- ------------- Total investments and other assets............................................................. 1,156,931 1,095,867 ------------- ------------- Utility Plant Plant in service Electric..................................................................................... 5,713,259 5,474,590 Gas.......................................................................................... 557,942 526,058 Common....................................................................................... 487,740 468,264 ------------- ------------- Total plant in service....................................................................... 6,758,941 6,468,912 Accumulated depreciation....................................................................... (2,161,984) (1,980,361) ------------- ------------- Net plant in service........................................................................... 4,596,957 4,488,551 Construction work in progress.................................................................. 436,440 308,908 Nuclear fuel (net of amortization)............................................................. 139,424 147,374 Plant held for future use...................................................................... 24,066 21,486 ------------- ------------- Net utility plant.............................................................................. 5,196,887 4,966,319 ------------- ------------- Deferred Charges Regulatory assets.............................................................................. 768,125 568,563 Other.......................................................................................... 70,436 36,554 ------------- ------------- Total deferred charges......................................................................... 838,561 605,117 ------------- ------------- Total Assets..................................................................................... $ 7,987,039 $ 7,374,357 ------------- ------------- ------------- -------------
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation. 31 CONSOLIDATED BALANCE SHEETS
AT DECEMBER 31, ---------------------------- 1993 1992 ------------- ------------- (IN THOUSANDS) LIABILITIES AND CAPITALIZATION Current Liabilities Short-term borrowings.......................................................................... $ -- $ 11,900 Current portions of long-term debt and preference stock........................................ 44,516 291,270 Accounts payable............................................................................... 195,534 175,495 Customer deposits.............................................................................. 22,345 20,027 Accrued taxes.................................................................................. 20,623 20,925 Accrued interest............................................................................... 58,541 55,537 Dividends declared............................................................................. 63,966 62,282 Accrued vacation costs......................................................................... 35,546 28,908 Other.......................................................................................... 38,716 2,567 ------------- ------------- Total current liabilities...................................................................... 479,787 668,911 ------------- ------------- Deferred Credits and Other Liabilities Deferred income taxes.......................................................................... 1,067,611 983,534 Deferred investment tax credits................................................................ 157,426 165,697 Pension and postemployment benefits............................................................ 183,043 5,352 Decommissioning of federal uranium enrichment facilities....................................... 46,858 55,000 Other.......................................................................................... 56,974 19,589 ------------- ------------- Total deferred credits and other liabilities................................................... 1,511,912 1,229,172 ------------- ------------- Capitalization Long-term debt................................................................................. 2,823,144 2,376,950 Preferred stock................................................................................ 59,185 59,185 Redeemable preference stock.................................................................... 342,500 395,500 Preference stock not subject to mandatory redemption........................................... 150,000 110,000 Common shareholders' equity.................................................................... 2,620,511 2,534,639 ------------- ------------- Total capitalization........................................................................... 5,995,340 5,476,274 ------------- ------------- Commitments, Guarantees, and Contingencies See Note 13 Total Liabilities and Capitalization............................................................. $ 7,987,039 $ 7,374,357 ------------- ------------- ------------- -------------
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation. 32 CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, ------------------------------------------- 1993 1992 1991 -------------- ------------ ------------- (IN THOUSANDS) Cash Flows From Operating Activities Net income....................................................................... $ 309,866 $ 264,347 $ 253,426 Adjustments to reconcile to net cash provided by operating activities: Cumulative effect of change in the method of accounting for income taxes....... -- -- (19,745) Depreciation and amortization.................................................. 314,027 273,549 244,017 Deferred income taxes.......................................................... 53,057 26,914 30,725 Investment tax credit adjustments.............................................. (8,444) (8,854) (6,225) Deferred fuel costs............................................................ 51,445 105,430 102,754 Write-down of financial investments and real estate projects................... -- -- 23,563 Allowance for equity funds used during construction............................ (14,492) (13,892) (23,596) Equity in earnings of affiliates and joint ventures (net)...................... (4,655) (11,525) 8,707 Changes in current assets...................................................... (37,252) (26,206) (6,563) Changes in current liabilities, other than short-term borrowings............... 71,153 (9,614) (6,027) Other.......................................................................... (31,919) (31,005) (5,373) -------------- ------------ ------------- Net cash provided by operating activities...................................... 702,786 569,144 595,663 -------------- ------------ ------------- Cash Flows From Financing Activities Proceeds from issuance of: Short-term borrowings (net).................................................... (11,900) (139,600) (15,530) Long-term debt................................................................. 1,206,350 603,400 1,015,950 Preference stock............................................................... 128,776 -- 34,801 Common stock................................................................... 57,379 355,759 32,263 Reacquisition of long-term debt.................................................. (1,012,514) (687,052) (959,379) Redemption of preference stock................................................... (144,310) (2,924) (22,800) Common stock dividends paid...................................................... (211,137) (189,180) (176,007) Preferred and preference stock dividends paid.................................... (42,425) (42,300) (42,743) Other............................................................................ (7,094) (399) (442) -------------- ------------ ------------- Net cash used in financing activities............................................ (36,875) (102,296) (133,887) -------------- ------------ ------------- Cash Flows From Investing Activities Utility construction expenditures................................................ (477,878) (389,416) (456,244) Allowance for equity funds used during construction.............................. 14,492 13,892 23,596 Nuclear fuel expenditures........................................................ (47,329) (39,486) (1,854) Deferred nuclear expenditures.................................................... (13,791) (15,809) (22,681) Deferred energy conservation expenditures........................................ (32,909) (19,918) (3,489) Nuclear decommissioning trust fund............................................... (9,699) (8,900) (8,900) Financial investments............................................................ 6,523 52,616 67,282 Real estate projects............................................................. (30,330) (23,385) (45,322) Power generation systems......................................................... (26,841) (31,483) (33,204) Other............................................................................ 8,965 4,746 (3,422) -------------- ------------ ------------- Net cash used in investing activities............................................ (608,797) (457,143) (484,238) -------------- ------------ ------------- Net Increase (Decrease) in Cash and Cash Equivalents............................... 57,114 9,705 (22,462) Cash and Cash Equivalents at Beginning of Year..................................... 27,122 17,417 39,879 -------------- ------------ ------------- Cash and Cash Equivalents at End of Year........................................... $ 84,236 $ 27,122 $ 17,417 -------------- ------------ ------------- -------------- ------------ ------------- Other Cash Flow Information Cash paid during the year for: Interest (net of amounts capitalized).......................................... $ 183,266 $ 183,209 $ 189,271 Income taxes................................................................... $ 126,034 $ 87,693 $ 16,078
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation. 33 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991 ------------------------------------------------------------------ NET UNREALIZED COMMON STOCK PENSION LOSS ON ------------------------- RETAINED LIABILITY MARKETABLE SHARES AMOUNT EARNINGS ADJUSTMENT SECURITIES ---------- ------------- ------------- ----------- ----------- (IN THOUSANDS) BALANCE AT DECEMBER 31, 1990............................ 125,039 $ 947,147 $ 1,139,999 $ -- $ (13,988) Deferred taxes on net unrealized loss................... 4,756 Net income.............................................. 253,426 Dividends declared Preferred and preference stock........................ (42,746) Common stock ($1.40 per share)........................ (176,584) Common stock issued..................................... 1,651 32,263 Other................................................... (199) Change in net unrealized loss on marketable securities............................................. 13,988 Change in deferred taxes on net unrealized loss......... (4,756) ---------- ------------- ------------- ----------- ----------- BALANCE AT DECEMBER 31, 1991............................ 126,690 979,211 1,174,095 -- -- Net income.............................................. 264,347 Dividends declared Preferred and preference stock........................ (42,247) Common stock ($1.43 per share)........................ (196,601) Common stock issued..................................... 17,098 356,230 Other................................................... (4) (439) 43 ---------- ------------- ------------- ----------- ----------- BALANCE AT DECEMBER 31, 1992............................ 143,784 1,335,002 1,199,637 -- -- Net income.............................................. 309,866 Dividends declared Preferred and preference stock........................ (41,839) Common stock ($1.47 per share)........................ (213,407) Common stock issued..................................... 2,250 57,379 Other................................................... (917) (3,117) Pension liability adjustment............................ (33,990) Deferred taxes on pension liability adjustment.......... 11,897 ---------- ------------- ------------- ----------- ----------- BALANCE AT DECEMBER 31, 1993............................ 146,034 $ 1,391,464 $ 1,251,140 $ (22,093) $ -- ---------- ------------- ------------- ----------- ----------- ---------- ------------- ------------- ----------- ----------- TOTAL AMOUNT ------------- BALANCE AT DECEMBER 31, 1990............................ $ 2,073,158 Deferred taxes on net unrealized loss................... 4,756 Net income.............................................. 253,426 Dividends declared Preferred and preference stock........................ (42,746) Common stock ($1.40 per share)........................ (176,584) Common stock issued..................................... 32,263 Other................................................... (199) Change in net unrealized loss on marketable securities............................................. 13,988 Change in deferred taxes on net unrealized loss......... (4,756) ------------- BALANCE AT DECEMBER 31, 1991............................ 2,153,306 Net income.............................................. 264,347 Dividends declared Preferred and preference stock........................ (42,247) Common stock ($1.43 per share)........................ (196,601) Common stock issued..................................... 356,230 Other................................................... (396) ------------- BALANCE AT DECEMBER 31, 1992............................ 2,534,639 Net income.............................................. 309,866 Dividends declared Preferred and preference stock........................ (41,839) Common stock ($1.47 per share)........................ (213,407) Common stock issued..................................... 57,379 Other................................................... (4,034) Pension liability adjustment............................ (33,990) Deferred taxes on pension liability adjustment.......... 11,897 ------------- BALANCE AT DECEMBER 31, 1993............................ $ 2,620,511 ------------- -------------
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation. 34 CONSOLIDATED STATEMENTS OF CAPITALIZATION
AT DECEMBER 31, ------------- 1993 ------------- (IN THOUSANDS) LONG-TERM DEBT First Refunding Mortgage Bonds of BGE 4% Series, due March 1, 1993............................................................................. $ -- 4 1/2% Series, due July 15, 1994......................................................................... -- 9 1/8% Series, due October 15, 1995...................................................................... 200,000 5 1/8% Series, due April 15, 1996........................................................................ 26,585 6 1/8% Series, due August 1, 1997........................................................................ 24,957 5 5/8% Installment Series, due August 15, 1998........................................................... -- 7% Series, due December 15, 1998......................................................................... 28,638 8.40% Series, due October 15, 1999....................................................................... 100,000 5 1/2% Series, due July 15, 2000......................................................................... 125,000 7 1/4% Series, due April 15, 2001........................................................................ 59,911 8 3/8% Series, due August 15, 2001....................................................................... 124,980 7 5/8% Series, due September 1, 2001..................................................................... -- 7 1/8% Series, due January 1, 2002....................................................................... 49,999 7 1/4% Series, due July 1, 2002.......................................................................... 125,000 7 1/2% Series, due July 1, 2002.......................................................................... -- 5 1/2% Installment Series, due July 15, 2002............................................................. 12,080 7 1/2% Series, due September 15, 2002.................................................................... -- 6 1/2% Series, due February 15, 2003..................................................................... 125,000 6 1/8% Series, due July 1, 2003.......................................................................... 125,000 8 1/8% Series, due February 1, 2004...................................................................... -- 5 1/2% Series, due April 15, 2004........................................................................ 125,000 6.80% Series, due September 15, 2004..................................................................... 20,000 8 3/8% Series, due September 15, 2006.................................................................... -- 7 1/2% Series, due January 15, 2007...................................................................... 125,000 8 1/4% Series, due September 15, 2007.................................................................... -- 6 5/8% Series, due March 15, 2008........................................................................ 125,000 9 3/8% Series, due July 1, 2008.......................................................................... -- 6.90% Installment Series, due September 15, 2009......................................................... 55,000 9 1/8% Series, due March 1, 2016......................................................................... -- 7 1/2% Series, due March 1, 2023......................................................................... 124,998 7 1/2% Series, due April 15, 2023........................................................................ 100,000 ------------- Total First Refunding Mortgage Bonds..................................................................... 1,802,148 ------------- Other long-term debt of BGE Medium-term notes, Series A.............................................................................. 23,500 Medium-term notes, Series B.............................................................................. 100,000 Medium-term notes, Series C.............................................................................. 173,050 9 1/2% Notes, due May 1, 1993............................................................................ -- Pollution control loan, due July 1, 2011................................................................. 36,000 Port facilities loan, due June 1, 2013................................................................... 48,000 Adjustable rate pollution control loan, due July 1, 2014................................................. 20,000 5.55% Pollution control revenue refunding loan, due July 15, 2014........................................ 47,000 Economic development loan, due December 1, 2018.......................................................... 35,000 ------------- Total other long-term debt............................................................................... 482,550 ------------- Long-term debt of Constellation Companies Mortgage and construction loans and other collateralized notes 7.75%, due December 16, 1995.............. $ -- Variable rates, due through 2009......................................................................... 151,251 8.5%, due May 1, 2001.................................................................................... -- 7.73%, due March 15, 2009................................................................................ 6,465 Loans under revolving credit agreements.................................................................. -- Unsecured notes.......................................................................................... 440,000 ------------- Total long-term debt of Constellation Companies.......................................................... 597,716 ------------- Unamortized discount and premium........................................................................... (17,754) Current portion of long-term debt.......................................................................... (41,516) ------------- Total long-term debt....................................................................................... 2,823,144 ------------- 1992 ------------- LONG-TERM DEBT First Refunding Mortgage Bonds of BGE 4% Series, due March 1, 1993............................................................................. $ 24,061 4 1/2% Series, due July 15, 1994......................................................................... 29,921 9 1/8% Series, due October 15, 1995...................................................................... 200,000 5 1/8% Series, due April 15, 1996........................................................................ 26,585 6 1/8% Series, due August 1, 1997........................................................................ 24,957 5 5/8% Installment Series, due August 15, 1998........................................................... 50,000 7% Series, due December 15, 1998......................................................................... 28,638 8.40% Series, due October 15, 1999....................................................................... 100,000 5 1/2% Series, due July 15, 2000......................................................................... -- 7 1/4% Series, due April 15, 2001........................................................................ 59,914 8 3/8% Series, due August 15, 2001....................................................................... 125,000 7 5/8% Series, due September 1, 2001..................................................................... 59,975 7 1/8% Series, due January 1, 2002....................................................................... 49,999 7 1/4% Series, due July 1, 2002.......................................................................... 125,000 7 1/2% Series, due July 1, 2002.......................................................................... 49,985 5 1/2% Installment Series, due July 15, 2002............................................................. 12,500 7 1/2% Series, due September 15, 2002.................................................................... 49,990 6 1/2% Series, due February 15, 2003..................................................................... -- 6 1/8% Series, due July 1, 2003.......................................................................... -- 8 1/8% Series, due February 1, 2004...................................................................... 74,983 5 1/2% Series, due April 15, 2004........................................................................ -- 6.80% Series, due September 15, 2004..................................................................... 20,000 8 3/8% Series, due September 15, 2006.................................................................... 74,960 7 1/2% Series, due January 15, 2007...................................................................... 125,000 8 1/4% Series, due September 15, 2007.................................................................... 75,000 6 5/8% Series, due March 15, 2008........................................................................ -- 9 3/8% Series, due July 1, 2008.......................................................................... 12,718 6.90% Installment Series, due September 15, 2009......................................................... 55,000 9 1/8% Series, due March 1, 2016......................................................................... 98,000 7 1/2% Series, due March 1, 2023......................................................................... -- 7 1/2% Series, due April 15, 2023........................................................................ -- ------------- Total First Refunding Mortgage Bonds..................................................................... 1,552,186 ------------- Other long-term debt of BGE Medium-term notes, Series A.............................................................................. 69,500 Medium-term notes, Series B.............................................................................. 100,000 Medium-term notes, Series C.............................................................................. 138,050 9 1/2% Notes, due May 1, 1993............................................................................ 100,000 Pollution control loan, due July 1, 2011................................................................. 36,000 Port facilities loan, due June 1, 2013................................................................... 48,000 Adjustable rate pollution control loan, due July 1, 2014................................................. 20,000 5.55% Pollution control revenue refunding loan, due July 15, 2014........................................ -- Economic development loan, due December 1, 2018.......................................................... 35,000 ------------- Total other long-term debt............................................................................... 546,550 ------------- Long-term debt of Constellation Companies Mortgage and construction loans and other collateralized notes 7.75%, due December 16, 1995.............. $ 5,575 Variable rates, due through 2009......................................................................... 160,572 8.5%, due May 1, 2001.................................................................................... 3,300 7.73%, due March 15, 2009................................................................................ -- Loans under revolving credit agreements.................................................................. 152,000 Unsecured notes.......................................................................................... 255,000 ------------- Total long-term debt of Constellation Companies.......................................................... 576,447 ------------- Unamortized discount and premium........................................................................... (8,463) Current portion of long-term debt.......................................................................... (289,770) ------------- Total long-term debt....................................................................................... 2,376,950 -------------
35 CONSOLIDATED STATEMENTS OF CAPITALIZATION (CONTINUED)
AT DECEMBER 31, ------------- 1993 ------------- (IN THOUSANDS) PREFERRED STOCK Cumulative, $100 par value, 1,000,000 shares authorized Series B, 4 1/2%, 222,921 shares outstanding, callable at $110 per share................................. 22,292 Series C, 4%, 68,928 shares outstanding, callable at $105 per share...................................... 6,893 Series D, 5.40%, 300,000 shares outstanding, callable at $101 per share.................................. 30,000 ------------- Total preferred stock...................................................................................... 59,185 ------------- PREFERENCE STOCK Cumulative, $100 par value, 6,500,000 shares authorized Redeemable preference stock 7.50%, 1986 Series, 470,000 and 485,000 shares outstanding, respectively. Callable at $105 per share prior to October 1, 1996 and at lesser amounts thereafter............................................... 47,000 6.75%, 1987 Series, 485,000 shares outstanding. Callable at $104.50 per share prior to April 1, 1997 and at lesser amounts thereafter............................................................................ 48,500 6.95%, 1987 Series, 500,000 shares outstanding........................................................... 50,000 7.64%, 1988 Series, 500,000 shares outstanding, called at $103.82 per share on July 1, 1993.............. -- 7.80%, 1989 Series, 500,000 shares outstanding........................................................... 50,000 8.25%, 1989 Series, 500,000 shares outstanding........................................................... 50,000 8.625%, 1990 Series, 650,000 shares outstanding.......................................................... 65,000 7.85%, 1991 Series, 350,000 shares outstanding........................................................... 35,000 Current portion of redeemable preference stock........................................................... (3,000) ------------- Total redeemable preference stock........................................................................ 342,500 ------------- Preference stock not subject to mandatory redemption 7.88%, 1971 Series, 500,000 shares outstanding, called at $101 per share on September 1, 1993............ $ -- 7.75%, 1972 Series, 400,000 shares outstanding, called at $101 per share on November 8, 1993............. -- 7.78%, 1973 Series, 200,000 shares outstanding, callable at $101 per share............................... 20,000 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003...................... 40,000 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003.................... 50,000 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004.................... 40,000 ------------- Total preference stock not subject to mandatory redemption............................................... 150,000 ------------- COMMON SHAREHOLDERS' EQUITY Common stock without par value, 175,000,000 shares authorized; 146,034,014 and 143,783,581 shares issued and outstanding at December 31, 1993 and 1992, respectively. (At December 31, 1993, 166,893 shares were reserved for the Employee Savings Plan and 4,770,773 shares were reserved for the Dividend Reinvestment and Stock Purchase Plan.)................................................................................. 1,391,464 Retained earnings.......................................................................................... 1,251,140 Pension liability adjustment............................................................................... (22,093) ------------- Total common shareholders' equity.......................................................................... 2,620,511 ------------- TOTAL CAPITALIZATION......................................................................................... $ 5,995,340 ------------- ------------- 1992 ------------- PREFERRED STOCK Cumulative, $100 par value, 1,000,000 shares authorized Series B, 4 1/2%, 222,921 shares outstanding, callable at $110 per share................................. 22,292 Series C, 4%, 68,928 shares outstanding, callable at $105 per share...................................... 6,893 Series D, 5.40%, 300,000 shares outstanding, callable at $101 per share.................................. 30,000 ------------- Total preferred stock...................................................................................... 59,185 ------------- PREFERENCE STOCK Cumulative, $100 par value, 6,500,000 shares authorized Redeemable preference stock 7.50%, 1986 Series, 470,000 and 485,000 shares outstanding, respectively. Callable at $105 per share prior to October 1, 1996 and at lesser amounts thereafter............................................... 48,500 6.75%, 1987 Series, 485,000 shares outstanding. Callable at $104.50 per share prior to April 1, 1997 and at lesser amounts thereafter............................................................................ 48,500 6.95%, 1987 Series, 500,000 shares outstanding........................................................... 50,000 7.64%, 1988 Series, 500,000 shares outstanding, called at $103.82 per share on July 1, 1993.............. 50,000 7.80%, 1989 Series, 500,000 shares outstanding........................................................... 50,000 8.25%, 1989 Series, 500,000 shares outstanding........................................................... 50,000 8.625%, 1990 Series, 650,000 shares outstanding.......................................................... 65,000 7.85%, 1991 Series, 350,000 shares outstanding........................................................... 35,000 Current portion of redeemable preference stock........................................................... (1,500) ------------- Total redeemable preference stock........................................................................ 395,500 ------------- Preference stock not subject to mandatory redemption 7.88%, 1971 Series, 500,000 shares outstanding, called at $101 per share on September 1, 1993............ $ 50,000 7.75%, 1972 Series, 400,000 shares outstanding, called at $101 per share on November 8, 1993............. 40,000 7.78%, 1973 Series, 200,000 shares outstanding, callable at $101 per share............................... 20,000 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003...................... -- 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003.................... -- 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004.................... -- ------------- Total preference stock not subject to mandatory redemption............................................... 110,000 ------------- COMMON SHAREHOLDERS' EQUITY Common stock without par value, 175,000,000 shares authorized; 146,034,014 and 143,783,581 shares issued and outstanding at December 31, 1993 and 1992, respectively. (At December 31, 1993, 166,893 shares were reserved for the Employee Savings Plan and 4,770,773 shares were reserved for the Dividend Reinvestment and Stock Purchase Plan.)................................................................................. 1,335,002 Retained earnings.......................................................................................... 1,199,637 Pension liability adjustment............................................................................... -- ------------- Total common shareholders' equity.......................................................................... 2,534,639 ------------- TOTAL CAPITALIZATION......................................................................................... $ 5,476,274 ------------- -------------
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation. 36 CONSOLIDATED STATEMENTS OF INCOME TAXES
YEAR ENDED DECEMBER 31, ---------------------------- 1993 1992 ------------- ------------- (DOLLAR AMOUNTS IN THOUSANDS) INCOME TAXES Current....................................................................................... $ 93,459 $ 85,287 ------------- ------------- Deferred Change in tax effect of temporary differences............................................... 63,972 44,975 Change in income taxes recoverable through future rates..................................... (30,086) (18,061) Deferred taxes credited (charged) to shareholders' equity................................... 11,897 -- ------------- ------------- Deferred taxes charged to expense........................................................... 45,783 26,914 ------------- ------------- Effect on deferred taxes of enacted change in federal corporate income tax rate Increase in deferred tax liability.......................................................... 20,105 -- Income taxes recoverable through future rates............................................... (12,831) -- ------------- ------------- Deferred taxes charged to expense........................................................... 7,274 -- ------------- ------------- Investment tax credit adjustments............................................................. (8,444) (8,854) ------------- ------------- Total income taxes............................................................................ 138,072 103,347 ------------- ------------- Cumulative effect of change in the method of accounting for income taxes Increase in deferred tax liability.......................................................... -- -- Income taxes recoverable through future rates............................................... -- -- ------------- ------------- Amount recognized in income................................................................. -- -- ------------- ------------- Income taxes per Consolidated Statements of Income............................................ $ 138,072 $ 103,347 ------------- ------------- ------------- ------------- RECONCILIATION OF INCOME TAXES COMPUTED AT STATUTORY FEDERAL RATE TO TOTAL INCOME TAXES Income before income taxes (including cumulative effect of accounting change)............... $ 447,938 $ 367,694 Statutory federal income tax rate......................................................... 35% 34% ------------- ------------- Income taxes computed at statutory federal rate........................................... 156,778 125,016 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities......................... 9,253 8,955 Allowance for equity funds used during construction..................................... (5,072) (4,723) Amortization of deferred investment tax credits......................................... (8,444) (8,854) Tax credits flowed through to income.................................................... (9,736) (804) Change in federal corporate income tax rate charged to expense.......................... 7,274 -- Reversal of deferred taxes on nonregulated activities................................... -- -- Amortization of deferred tax rate differential on regulated activities.................. (5,789) (7,365) Other................................................................................... (6,192) (8,878) ------------- ------------- Total income taxes........................................................................ $ 138,072 $ 103,347 ------------- ------------- ------------- ------------- Effective federal income tax rate......................................................... 30.8% 28.1% 1991 ------------- INCOME TAXES Current....................................................................................... $ 61,047 ------------- Deferred Change in tax effect of temporary differences............................................... 28,361 Change in income taxes recoverable through future rates..................................... (12,625) Deferred taxes credited (charged) to shareholders' equity................................... (4,756) ------------- Deferred taxes charged to expense........................................................... 10,980 ------------- Effect on deferred taxes of enacted change in federal corporate income tax rate Increase in deferred tax liability.......................................................... -- Income taxes recoverable through future rates............................................... -- ------------- Deferred taxes charged to expense........................................................... -- ------------- Investment tax credit adjustments............................................................. (6,225) ------------- Total income taxes............................................................................ 65,802 ------------- Cumulative effect of change in the method of accounting for income taxes Increase in deferred tax liability.......................................................... 286,787 Income taxes recoverable through future rates............................................... (267,042) ------------- Amount recognized in income................................................................. 19,745 ------------- Income taxes per Consolidated Statements of Income............................................ $ 85,547 ------------- ------------- RECONCILIATION OF INCOME TAXES COMPUTED AT STATUTORY FEDERAL RATE TO TOTAL INCOME TAXES Income before income taxes (including cumulative effect of accounting change)............... $ 319,228 Statutory federal income tax rate......................................................... 34% ------------- Income taxes computed at statutory federal rate........................................... 108,538 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities......................... 7,008 Allowance for equity funds used during construction..................................... (8,023) Amortization of deferred investment tax credits......................................... (9,344) Tax credits flowed through to income.................................................... (1,335) Change in federal corporate income tax rate charged to expense.......................... -- Reversal of deferred taxes on nonregulated activities................................... (19,745) Amortization of deferred tax rate differential on regulated activities.................. (5,024) Other................................................................................... (6,273) ------------- Total income taxes........................................................................ $ 65,802 ------------- ------------- Effective federal income tax rate......................................................... 20.6%
AT DECEMBER 31, ------------- 1993 ------------- (DOLLAR AMOUNTS IN THOUSANDS) DEFERRED INCOME TAXES Deferred tax liabilities Accelerated depreciation.................................................................................... $ 789,165 Allowance for funds used during construction................................................................ 202,490 Income taxes recoverable through future rates............................................................... 90,950 Deferred termination and postemployment costs............................................................... 55,890 Deferred fuel costs......................................................................................... 45,518 Leveraged leases............................................................................................ 32,613 Percentage repair allowance................................................................................. 35,431 Other....................................................................................................... 129,130 ------------- Total deferred tax liabilities.............................................................................. 1,381,187 ------------- Deferred tax assets Alternative minimum tax..................................................................................... 72,187 Accrued pension and postemployment benefit costs............................................................ 67,016 Deferred investment tax credits............................................................................. 55,099 Other....................................................................................................... 119,274 ------------- Total deferred tax assets................................................................................... 313,576 ------------- Deferred income taxes per Consolidated Balance Sheets......................................................... $ 1,067,611 ------------- ------------- 1992 ------------- DEFERRED INCOME TAXES Deferred tax liabilities Accelerated depreciation.................................................................................... $ 714,019 Allowance for funds used during construction................................................................ 199,577 Income taxes recoverable through future rates............................................................... 73,759 Deferred termination and postemployment costs............................................................... -- Deferred fuel costs......................................................................................... 61,709 Leveraged leases............................................................................................ 33,867 Percentage repair allowance................................................................................. 33,367 Other....................................................................................................... 95,995 ------------- Total deferred tax liabilities.............................................................................. 1,212,293 ------------- Deferred tax assets Alternative minimum tax..................................................................................... 72,189 Accrued pension and postemployment benefit costs............................................................ 1,595 Deferred investment tax credits............................................................................. 56,337 Other....................................................................................................... 98,638 ------------- Total deferred tax assets................................................................................... 228,759 ------------- Deferred income taxes per Consolidated Balance Sheets......................................................... $ 983,534 ------------- -------------
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation. 37 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. SIGNIFICANT ACCOUNTING POLICIES NATURE OF THE BUSINESS Baltimore Gas and Electric Company (BGE) and Subsidiaries (collectively, the Company) is primarily an electric and gas utility serving a territory which encompasses Baltimore City and all or part of nine Central Maryland counties. The Company is also engaged in diversified businesses as described further in Note 3. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of BGE and all subsidiaries in which BGE owns directly or indirectly a majority of the voting stock. Intercompany balances and transactions have been eliminated in consolidation. Under this policy, the accounts of Constellation Holdings, Inc. and its subsidiaries (collectively, the Constellation Companies) and BNG, Inc. are consolidated in the financial statements. Safe Harbor Water Power Corporation is reported under the equity method. Corporate joint ventures, partnerships, and affiliated companies in which a 20% to 50% voting interest is held are accounted for under the equity method, unless control is evident, in which case the entity is consolidated. Investments in power generation systems and certain financial investments in which less than a 20% voting interest is held are accounted for under the cost method, unless significant influence is exercised over the entity, in which case the investment is accounted for under the equity method. REGULATION OF UTILITY OPERATIONS BGE's utility operations are subject to regulation by the Public Service Commission of Maryland (PSC). The accounting policies and practices used in the determination of service rates are also generally used for financial reporting purposes in accordance with generally accepted accounting principles for regulated industries. See Note 5. UTILITY REVENUES BGE recognizes utility revenues as service is rendered to customers. FUEL AND PURCHASED ENERGY COSTS Subject to the approval of the PSC, the cost of fuel used in generating electricity, net of revenues from interchange sales, and the cost of gas sold may be recovered through zero-based electric fuel rate (see Note 13) and purchased gas adjustment clauses. The difference between actual fuel costs and fuel revenues is deferred on the balance sheet to be recovered from or refunded to customers in future periods. The electric fuel rate formula is based upon the latest twenty-four-month generation mix, subject to a minimum level of nuclear generation, and the latest three-month average fuel cost for each generating unit. The fuel rate does not change unless the calculated rate is more than 5% above or below the rate then in effect. The purchased gas adjustment is based on recent annual volumes of gas and the related current prices charged by BGE's gas suppliers. Any deferred underrecoveries or overrecoveries of purchased gas costs for the twelve months ended November 30 each year are charged or credited to customers over the ensuing calendar year. INCOME TAXES The Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," effective January 1, 1991. Statement No. 109 requires the use of the liability method of accounting for income taxes. Under the liability method, the deferred tax liability represents the tax effect of temporary differences between the financial statement and tax bases of assets and liabilities. It is measured using presently enacted tax rates. The portion of BGE's deferred tax liability applicable to utility operations which has not been reflected in current service rates represents income taxes recoverable through future rates. It has been recorded as a regulatory asset on the balance sheet. Deferred income tax expense represents the net change in the deferred tax liability and regulatory asset during the year, exclusive of amounts charged or credited to common shareholders' equity. The 1993 and 1992 current tax expense consists solely of regular tax. The 1991 current tax expense consists of a regular tax of $46.8 million and an alternative minimum tax (AMT) of $14.2 million. The AMT liabilities generated in 1991 and prior years can be carried forward indefinitely as tax credits to future years in which the regular tax liability exceeds the AMT liability. As of December 31, 1993, this carryforward totaled $73.2 million. As a result of its effect on nonregulated activities, the cumulative effect of the change in the method of accounting for income taxes resulted in an increase in 1991 net income of $19.7 million, or 16 CENTS per common share, because of the reversal of deferred income taxes on nonregulated activities accrued in prior years at tax rates in excess of the 34% tax rate in effect at that time. 38 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) The investment tax credit (ITC) associated with BGE's regulated utility operations has been deferred and is amortized to income ratably over the lives of the subject property. ITC and other tax credits associated with nonregulated diversified business activities other than leveraged leases are flowed through to income. As of December 31, 1993, the Company had energy and other tax credit carryforwards of $4.8 million which expire in the years 2005 through 2008. BGE's utility revenue from system sales is subject to the Maryland public service company franchise tax in lieu of a state income tax. The franchise tax is included in taxes other than income taxes in the Consolidated Statements of Income. INVENTORY VALUATION Fuel stocks and materials and supplies are generally stated at average cost. REAL ESTATE PROJECTS Real estate projects consist of the Constellation Companies' investment in rental and operating properties and properties under development. Rental and operating properties are held for investment. Properties under development are held for future development and sale. Costs incurred in the acquisition and active development of such properties are capitalized. Rental and operating properties and properties under development are stated at cost unless the amount invested exceeds the amounts expected to be recovered through operations and sales. In these cases, the projects are written down to the amount estimated to be recoverable. INVESTMENTS Marketable equity securities are stated at the lower of cost or market value, and other securities are stated at cost. Where appropriate, cost reflects amortization of premium and discount computed on a straight-line basis. Gains and losses on the sale of the Constellation Companies' investment securities are included in revenues from diversified activities on the income statement and are recognized upon realization on a specific identification basis. Gains and losses on the sale of BGE's nuclear decommissioning trust fund securities are included in net other income and deductions on the income statement and are recognized upon realization on a specific identification basis. Statement of Financial Accounting Standards No. 115, which must be adopted in 1994, requires that investments in equity securities having readily determinable fair values and debt securities other than those which the Company has the positive intent and ability to hold to maturity be recorded at fair value rather than at amortized cost. Changes in the fair value of these securities will be recorded in shareholders' equity except for trading securities, for which such changes will be recorded in income. Adoption of this statement is not expected to have a material impact on the Company's financial statements. UTILITY PLANT, DEPRECIATION AND AMORTIZATION, AND DECOMMISSIONING Utility plant is stated at original cost, which includes material, labor, and, where applicable, construction overhead costs and an allowance for funds used during construction. Additions to utility plant and replacements of units of property are capitalized to utility plant accounts. Maintenance and repairs of property and replacements of items of property determined to be less than a unit of property are charged to maintenance expense. Depreciation is generally computed using composite straightline rates applied to the average investment in classes of depreciable property. The composite depreciation rates by class of depreciable property are 2.80% for the Calvert Cliffs Nuclear Power Plant, 2.75% for the Brandon Shores Power Plant, 3.26% for other electric plant, 3.12% for gas plant, and 4.02% for common plant other than vehicles. Vehicles are depreciated based on their estimated useful lives. BGE owns an undivided interest in the Keystone and Conemaugh electric generating plants located in western Pennsylvania, as well as in the transmission line which transports the plants' output to the joint owners' service territories. BGE's ownership interest in these plants is 20.99% and 10.56%, respectively, and represents a net investment of $128 million as of December 31, 1993. Financing and accounting for these properties are the same as for wholly owned utility plant. Nuclear fuel expenditures are amortized as a component of actual fuel costs based on the energy produced over the life of the fuel. Fees for the future disposal of spent fuel are paid quarterly to the Department of Energy and are accrued based on the kilowatt-hours of electricity generated. Nuclear fuel expenses are subject to recovery through the electric fuel rate. Nuclear decommissioning costs are accrued by and recovered through a sinking fund methodology. In its April 1993 rate order, the PSC granted BGE revenue to accumulate a decommissioning reserve of $336 million in 39 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 1. SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) 1992 dollars by the end of Calvert Cliffs' service life in 2016, adjusted to reflect expected inflation, to decommission the radioactive portion of the plant. The total decommissioning reserve of $93.4 million and $77.8 million at December 31, 1993 and 1992, respectively, is included in accumulated depreciation in the Consolidated Balance Sheets. In accordance with Nuclear Regulatory Commission (NRC) regulations, BGE has established an external decommissioning trust to which a portion of accrued decommissioning costs has been contributed. 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, provided that the facility-specific estimate is equal to or greater than that of the NRC formula. Subsequent to the PSC's April 1993 rate order, the NRC updated its generic formula to reflect substantially higher waste burial charges. The revised NRC formula generates a decommissioning cost estimate of $703 million in 1992 dollars. Additionally, the Company initiated a facility-specific study which, when completed, is expected to generate an estimate of the cost to decommission the radioactive portion of the plant which is less than the NRC formula estimate. The Company is currently completing the facility-specific study and plans to request the NRC to permit the use of the facility-specific decommissioning cost estimate as a basis of funding these costs and providing the requisite financial assurance. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION AND CAPITALIZED INTEREST The allowance for funds used during construction (AFC) is an accounting procedure which capitalizes the cost of funds used to finance utility construction projects as part of utility plant on the balance sheet, crediting the cost as a noncash item on the income statement. The cost of borrowed and equity funds is segregated between interest expense and other income, respectively. BGE recovers the capitalized AFC and a return thereon after the related utility plant is placed in service and included in depreciable assets and rate base. During the period January 1, 1991 through April 23, 1993, the Company accrued AFC at a pre-tax rate of 9.94%, compounded annually. Effective April 24, 1993, a rate order of the PSC reduced the pre-tax AFC rate to 9.40%, compounded annually. Effective January 1, 1992, the PSC authorized the accrual of AFC on all electric, gas, and common utility construction projects with a construction period of more than one month. Prior to 1992, AFC was accrued on major electric projects only. The Constellation Companies capitalize interest on qualifying real estate and power generation development projects. BGE capitalizes interest on certain deferred fuel costs as discussed in Note 5. LONG-TERM DEBT The discount or premium and expense of issuance associated with long-term debt are deferred and amortized over the original lives of the respective debt issues. Gains and losses on the reacquisition of debt are amortized over the remaining original lives of the issuances. CASH FLOWS For the purpose of reporting cash flows, highly liquid investments purchased with a maturity of three months or less are considered to be cash equivalents. 40 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 2. SEGMENT INFORMATION
YEAR ENDED DECEMBER 31, ------------------------------------------- 1993 1992 1991 ------------- ------------- ------------- (IN THOUSANDS) Electric Revenues......................................................................... $ 2,115,155 $ 1,967,923 $ 1,994,525 Income from operations........................................................... 538,340 441,784 444,530 Income from operations net of income taxes....................................... 402,893 350,429 352,385 Depreciation..................................................................... 203,476 191,970 173,349 Construction expenditures (including AFC)........................................ 419,519 346,728 406,008 Identifiable assets at December 31............................................... 6,025,798 5,508,008 5,374,940 Gas Revenues......................................................................... $ 435,849 $ 402,937 $ 358,195 Income from operations........................................................... 39,426 45,552 35,607 Income from operations net of income taxes....................................... 33,188 37,514 30,945 Depreciation..................................................................... 22,995 21,364 18,896 Construction expenditures (including AFC)........................................ 58,359 42,688 50,236 Identifiable assets at December 31............................................... 694,977 579,386 555,609 Diversified Businesses Revenues......................................................................... $ 117,710 $ 120,483 $ 96,133 Income from operations........................................................... 43,234 48,009 9,051 Income from operations net of income taxes....................................... 46,847 44,055 20,313 Depreciation..................................................................... 10,303 10,149 9,019 Cumulative effect of change in the method of accounting for income taxes......... -- -- 19,745 Identifiable assets at December 31............................................... 1,096,220 1,023,315 1,001,313 Total Revenues......................................................................... $ 2,668,714 $ 2,491,343 $ 2,448,853 Income from operations........................................................... 621,000 535,345 489,188 Income from operations net of income taxes....................................... 482,928 431,998 403,641 Depreciation..................................................................... 236,774 223,483 201,264 Cumulative effect of change in the method of accounting for income taxes......... -- -- 19,745 Construction expenditures (including AFC)........................................ 477,878 389,416 456,244 Identifiable assets at December 31............................................... 7,816,995 7,110,709 6,931,862 Other assets at December 31...................................................... 170,044 263,648 206,127 Total assets at December 31...................................................... 7,987,039 7,374,357 7,137,989
41 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 3. SUBSIDIARY INFORMATION Diversified businesses consist of the operations of Constellation Holdings, Inc. and its subsidiaries and BNG, Inc. Constellation Holdings, Inc., a wholly owned subsidiary, holds all of the stock of three other subsidiaries, Constellation Real Estate Group, Inc., Constellation Energy, Inc., and Constellation Investments, Inc. These companies are engaged in real estate development and ownership of senior living facilities; development, ownership, and operation of power generation systems; and financial investments, respectively. BNG, Inc. is a wholly owned subsidiary which invests in natural gas reserves. BGE's investment in Safe Harbor Water Power Corporation, a producer of hydroelectric power, represents two-thirds of Safe Harbor's total capital stock, including one-half of the voting stock, and a two-thirds interest in its retained earnings. The following is condensed financial information for Constellation Holdings, Inc. and its subsidiaries. Similar information is not presented for Safe Harbor Water Power Corporation and BNG, Inc. as the financial position and results of operations of these entities are immaterial. The condensed financial information for the Constellation Companies does not reflect the elimination of intercompany balances or transactions which are eliminated in the Company's consolidated financial statements.
1993 1992 1991 ------------- ------------- ------------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Income Statements Revenues Real estate projects........................................................... $ 77,598 $ 76,582 $ 75,205 Power generation systems....................................................... 24,971 28,084 17,732 Financial investments.......................................................... 21,195 21,485 8,059 ------------- ------------- ------------- Total revenues................................................................. 123,764 126,151 100,996 Expenses other than interest and income taxes.................................... 80,427 77,872 91,848 ------------- ------------- ------------- Income from operations........................................................... 43,337 48,279 9,148 Minority interest................................................................ (280) 718 3,550 Interest expense................................................................. (33,143) (30,103) (32,938) Income tax benefit (expense)..................................................... 1,984 (3,637) 9,005 Cumulative effect of change in the method of accounting for income taxes......... -- -- 19,745 ------------- ------------- ------------- Net income....................................................................... $ 11,898 $ 15,257 $ 8,510 ------------- ------------- ------------- ------------- ------------- ------------- Contribution to the Company's earnings per share of common stock................... $ .08 $ .11 $ .07 ------------- ------------- ------------- ------------- ------------- ------------- Balance Sheets Current assets................................................................... $ 54,039 $ 29,899 $ 20,463 Noncurrent assets................................................................ 1,036,507 990,273 976,179 ------------- ------------- ------------- Total assets..................................................................... $ 1,090,546 $ 1,020,172 $ 996,642 ------------- ------------- ------------- ------------- ------------- ------------- Current liabilities.............................................................. $ 24,201 $ 113,404 $ 285,130 Noncurrent liabilities........................................................... 759,048 611,370 431,370 Shareholder's equity............................................................. 307,297 295,398 280,142 ------------- ------------- ------------- Total liabilities and shareholder's equity....................................... $ 1,090,546 $ 1,020,172 $ 996,642 ------------- ------------- ------------- ------------- ------------- -------------
42 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 4. REAL ESTATE PROJECTS AND FINANCIAL INVESTMENTS Real estate projects consist of the following investments held by the Constellation Companies:
AT DECEMBER 31, ------------------------ 1993 1992 ----------- ----------- (IN THOUSANDS) Properties under development........................................................................... $ 249,473 $ 231,856 Rental and operating properties (net of accumulated depreciation)...................................... 237,194 227,412 Other real estate ventures............................................................................. 730 2,774 ----------- ----------- Total.................................................................................................. $ 487,397 $ 462,042 ----------- ----------- ----------- -----------
In 1991, a subsidiary of Constellation Holdings, Inc. recognized a loss of $10 million to write down the carrying value of certain operating properties and properties under development to reflect the depressed real estate and economic markets. Financial investments consist of the following investments held by the Constellation Companies:
AT DECEMBER 31, ------------------------ 1993 1992 ----------- ----------- (IN THOUSANDS) Insurance companies.................................................................................... $ 83,275 $ 93,048 Financial limited partnerships......................................................................... 44,903 41,076 Leveraged leases....................................................................................... 38,669 39,441 Marketable equity securities........................................................................... 42,681 25,304 Other securities....................................................................................... 3,787 8,142 ----------- ----------- Total.................................................................................................. $ 213,315 $ 207,011 ----------- ----------- ----------- -----------
In 1991, a subsidiary of Constellation Holdings, Inc. recognized a loss of $10.5 million to write-down the carrying value of financial investments to reflect previously unrealized losses on certain marketable equity securities. The securities written down were subsequently sold. A subsidiary of Constellation Holdings, Inc. also recognized a loss of $3.1 million on two financial limited partnerships that were adjusted to reflect market value when the partnerships were reclassified as short-term investments. As of December 31, 1993, gross unrealized gains and losses applicable to marketable equity securities totaled $1.8 and $0.5 million, respectively. Net realized gains (losses) from financial investments included in net income totaled $6.5 million in 1993, $9.8 million in 1992, and $(11.6) million in 1991. NOTE 5. REGULATORY ASSETS Certain utility expenses and credits normally reflected in income are deferred on the balance sheet as regulatory assets and liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers in utility revenues. The following table sets forth BGE's regulatory assets.
AT DECEMBER 31, ------------------------ 1993 1992 ----------- ----------- (IN THOUSANDS) Income taxes recoverable through future rates.......................................................... $ 259,856 $ 216,939 Deferred fuel costs.................................................................................... 130,052 181,497 Deferred termination benefit costs..................................................................... 96,793 -- Deferred nuclear expenditures.......................................................................... 86,726 76,549 Deferred postemployment benefit costs.................................................................. 62,892 -- Deferred cost of decommissioning federal uranium enrichment facilities................................. 49,562 55,000 Deferred energy conservation expenditures.............................................................. 38,655 20,519 Deferred environmental costs........................................................................... 32,966 -- Other.................................................................................................. 10,623 18,059 ----------- ----------- Total.................................................................................................. $ 768,125 $ 568,563 ----------- ----------- ----------- -----------
Income taxes recoverable through future rates represent principally the tax effect of depreciation differences not normalized and the allowance for equity funds used during construction, offset by unamortized deferred tax rate differentials and deferred taxes on deferred ITC. These amounts are amortized as the related temporary differences reverse. See Note 1 for a further discussion of income taxes. 43 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 5. REGULATORY ASSETS (CONTINUED) Deferred fuel costs represent the difference between actual fuel costs and the fuel rate revenues under BGE's fuel clauses (see Note 1). Deferred fuel costs are amortized as they are collected from customers. The underrecovered costs deferred under the fuel clauses were as follows:
AT DECEMBER 31, ------------------------ 1993 1992 ----------- ----------- (IN THOUSANDS) Electric Costs deferred....................................................................................... $ 155,901 $ 210,483 Reserve for possible disallowance of replacement energy costs (see Note 13).......................... (35,000) (35,000) ----------- ----------- Net electric......................................................................................... 120,901 175,483 Gas.................................................................................................... 9,151 6,014 ----------- ----------- Total.................................................................................................. $ 130,052 $ 181,497 ----------- ----------- ----------- -----------
Deferred termination benefit costs represent the net unamortized balance of the cost of certain termination benefits (see Note 7) applicable to BGE's regulated operations. These costs are being amortized over a five-year period in accordance with rate actions of the PSC. Deferred nuclear expenditures represent the net unamortized balance of certain operations and maintenance costs which are being amortized over the remaining life of the Calvert Cliffs Nuclear Power Plant in accordance with orders of the PSC. These expenditures consist of costs incurred from 1979 through 1982 for inspecting and repairing seismic pipe supports, expenditures incurred from 1989 through 1993 associated with nonrecurring phases of certain nuclear operations projects, and expenditures incurred during 1990 for investigating leaks in the pressurizer heater sleeves. Deferred postemployment benefit costs represent the excess of such costs recognized in accordance with Statements of Financial Accounting Standards No. 106 and No. 112 over the amounts reflected in utility rates. These costs will be amortized over a 15-year period beginning no later than 1998 (see Note 6). Deferred cost of decommissioning federal uranium enrichment facilities represents the unamortized portion of BGE's required contributions to a fund for decommissioning and decontaminating the Department of Energy's (DOE) uranium enrichment facilities. The Energy Policy Act of 1992 requires domestic utilities to make such contributions, which are generally payable over a fifteen-year period with escalation for inflation and are based upon the amount of uranium enriched by DOE for each utility. These costs are being amortized over the contribution period as a cost of fuel. Deferred energy conservation expenditures represent the net unamortized balance of certain operations costs which are being amortized over five years in accordance with orders of the PSC. These expenditures consist of labor, materials, and indirect costs associated with the conservation programs approved by the PSC. Deferred environmental costs represent the estimated costs of investigating contamination and performing certain remediation activities at contaminated Company-owned sites (see Note 13). These costs are generally amortized over the estimated term of the remediation process. Electric deferred fuel costs in excess of $72.8 million are excluded from rate base by the PSC for ratemaking purposes. Effective April 24, 1993, BGE has been authorized by the PSC to accrue carrying charges on electric deferred fuel costs excluded from rate base. These carrying charges are accrued prospectively at the 9.40% authorized rate of return. The income effect of the equity funds portion of the carrying charges is being deferred until such amounts are recovered in utility service rates subsequent to the completion of the fuel rate proceeding examining the 1989-1991 outages at Calvert Cliffs Nuclear Power Plant as discussed in Note 13. NOTE 6. PENSION AND POSTEMPLOYMENT BENEFITS PENSION BENEFITS The Company sponsors several noncontributory defined benefit pension plans, the largest of which (the Pension Plan) covers substantially all BGE employees and certain employees of the Constellation Companies. The other plans, which are not material in amount, provide supplemental benefits to certain non-employee directors and key employees. Benefits under the plans are generally based on age, years of service, and compensation levels. 44 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 6. PENSION AND POSTEMPLOYMENT BENEFITS (CONTINUED) Prior service cost associated with retroactive plan amendments is amortized on a straightline basis over the average remaining service period of active employees. The Company's funding policy is to contribute annually the cost of the Pension Plan as determined under the projected unit credit cost method. Pension Plan assets at December 31, 1993 consisted primarily of marketable fixed income and equity securities, group annuity contracts, and short-term investments. The following tables set forth the combined funded status of the plans and the composition of total net pension cost. Due to declining interest rates, the Company reduced the discount rate used to measure its liability for pension, postretirement, and postemployment benefits to 7.5% as of December 31, 1993. This decrease in the discount rate, coupled with the increased pension liability resulting from the 1993 Voluntary Special Early Retirement Program, produced an accumulated pension obligation greater than the fair value of the Pension Plan's assets. As a result, the Company recorded a pension liability adjustment, a portion of which was charged to shareholders' equity.
AT DECEMBER 31, ------------------------ 1993 1992 ----------- ----------- (IN THOUSANDS) Vested benefit obligation.............................................................................. $ 677,069 $ 485,098 Nonvested benefit obligation........................................................................... 11,359 9,814 ----------- ----------- Accumulated benefit obligation......................................................................... 688,428 494,912 Projected benefits related to increase in future compensation levels................................... 109,161 86,882 ----------- ----------- Projected benefit obligation........................................................................... 797,589 581,794 Plan assets at fair value.............................................................................. (605,629) (542,190) ----------- ----------- Projected benefit obligation less plan assets.......................................................... 191,960 39,604 Unrecognized prior service cost........................................................................ (21,252) (17,671) Unrecognized net loss.................................................................................. (148,450) (28,017) Pension liability adjustment........................................................................... 58,553 -- Unamortized net asset from adoption of FASB Statement No. 87........................................... 1,812 2,039 ----------- ----------- Accrued pension liability (asset)...................................................................... $ 82,623 $ (4,045) ----------- ----------- ----------- -----------
YEAR ENDED DECEMBER 31, ---------------------------------- 1993 1992 1991 ---------- ---------- ---------- (IN THOUSANDS) Components of net pension cost Service cost-benefits earned during the period............................................. $ 11,645 $ 11,771 $ 11,729 Interest cost on projected benefit obligation.............................................. 51,183 47,355 43,143 Actual return on plan assets............................................................... (56,225) (33,685) (56,737) Net amortization and deferral.............................................................. 6,591 (12,257) 12,810 ---------- ---------- ---------- Total net pension cost..................................................................... 13,194 13,184 10,945 Amount capitalized as construction cost.................................................... (1,800) (1,839) (1,500) ---------- ---------- ---------- Amount charged to expense.................................................................. $ 11,394 $ 11,345 $ 9,445 ---------- ---------- ---------- ---------- ---------- ----------
Net pension cost shown above does not include the cost of termination benefits described in Note 7. The Company also sponsors a defined contribution savings plan covering all eligible BGE employees and certain employees of the Constellation Companies. Under this plan, the Company makes contributions on behalf of participants. Company contributions to this plan totaled $9 million, $14.8 million, and $10.6 million in 1993, 1992, and 1991, respectively. POSTRETIREMENT BENEFITS The Company sponsors defined benefit postretirement health care and life insurance plans which cover substantially all BGE employees and certain employees of the Constellation Companies. Benefits under the plans are generally based on age, years of service, and pension benefit levels. The postretirement benefit (PRB) plans are unfunded. Substantially all of the health care plans are contributory, and participant contributions for employees who retire after June 30, 1992 are based on age and years of service. Retiree contributions increase commensurate with the expected increase in medical costs. The postretirement life insurance plan is noncontributory. 45 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 6. PENSION AND POSTEMPLOYMENT BENEFITS (CONTINUED) Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 106, which requires a change in the method of accounting for postretirement benefits other than pensions from the pay-as-you-go method used prior to 1993 to the accrual method. The transition obligation existing at the beginning of 1993 is being amortized over a twenty-year period. In April 1993, the PSC issued a rate order authorizing BGE to recognize in operating expense one-half of the annual increase in PRB costs applicable to regulated operations as a result of the adoption of Statement No. 106 and to defer the remainder of the annual increase in these costs for inclusion in BGE's next base rate proceeding. In accordance with the PSC's Order, the increase in annual PRB costs applicable to regulated operations for the period January through April 1993, net of amounts capitalized as construction cost, has been deferred. This amount, which totaled $5.7 million, as well as all amounts to be deferred prior to completion of BGE's next base rate proceeding, will be amortized over a 15-year period beginning no later than 1998 in accordance with the PSC's Order. This phase-in approach meets the guidelines established by the Emerging Issues Task Force of the Financial Accounting Standards Board for deferring post-retirement benefit costs as a regulatory asset. Accrual-basis PRB costs applicable to nonregulated operations are charged to expense. The following table sets forth the components of the accumulated postretirement benefit obligation and a reconciliation of these amounts to the accrued postretirement benefit liability.
AT DECEMBER 31, ---------------------------------------------------- 1993 1992 ------------------------- ------------------------- LIFE LIFE HEALTH CARE INSURANCE HEALTH CARE INSURANCE ------------ ----------- ------------ ----------- (IN THOUSANDS) Accumulated postretirement benefit obligation: Retirees................................................................ $ 182,638 $ 45,461 $ 116,935 $ 34,600 Fully eligible active employees......................................... 19,177 839 18,082 143 Other active employees.................................................. 58,832 15,377 54,208 16,458 ------------ ----------- ------------ ----------- Total accumulated postretirement benefit obligation..................... 260,647 61,677 189,225 51,201 Unrecognized transition obligation...................................... (179,764) (48,641) (189,225) (51,201) Unrecognized net loss................................................... (36,675) (9,072) -- -- ------------ ----------- ------------ ----------- Accrued postretirement benefit liability.................................. $ 44,208 $ 3,964 $ -- $ -- ------------ ----------- ------------ ----------- ------------ ----------- ------------ -----------
The following table sets forth the composition of net postretirement benefit cost.
YEAR ENDED DECEMBER 31, 1993 -------------- (IN THOUSANDS) Components of net postretirement benefit cost: Service cost--benefits earned during the period................................................................. $ 4,373 Interest cost on accumulated postretirement benefit obligation.................................................. 20,451 Amortization of transition obligation........................................................................... 12,021 -------------- Total net postretirement benefit cost........................................................................... 36,845 Amount capitalized as construction cost......................................................................... (5,898) Amount deferred................................................................................................. (11,965) -------------- Amount charged to expense....................................................................................... $ 18,982 -------------- --------------
Net postretirement benefit costs shown above do not include the cost of termination benefits described in Note 7. Postretirement benefit costs recognized under the pay-as-you-go method were as follows:
YEAR ENDED DECEMBER 31, --------------------- 1992 1991 ---------- --------- (IN THOUSANDS) Total postretirement benefit cost.......................................................................... $ 11,676 $ 9,741 Amount capitalized as construction cost.................................................................... (1,911) (1,573) ---------- --------- Amount charged to expense.................................................................................. $ 9,765 $ 8,168 ---------- --------- ---------- ---------
46 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 6. PENSION AND POSTEMPLOYMENT BENEFITS (CONTINUED) OTHER POSTEMPLOYMENT BENEFITS The Company provides certain pay continuation payments and health and life insurance benefits to employees of BGE and certain of the Constellation Companies who are determined to be disabled under BGE's Long-Term Disability Plan. The Company adopted Statement of Financial Accounting Standards No. 112, which requires a change in the method of accounting for these benefits from the pay-as-you-go method to an accrual method, as of December 31, 1993. The liability for these benefits totaled $52.1 million as of December 31, 1993, and the portion of this liability attributable to regulated activities was deferred. The amounts deferred will be amortized over a 15-year period beginning no later than 1998. The adoption of Statement No. 112 did not have a material impact on net income. The increase in the annual cost of these benefits subsequent to the adoption of accrual accounting is not expected to have a material impact on the Company's financial statements. ASSUMPTIONS The pension and postemployment benefit liabilities were determined using the following assumptions.
AT DECEMBER 31, ----------- 1993 ----------- Assumptions: Discount rate................................................................................................ 7.5% Average increase in future compensation levels............................................................... 4.5% Expected long-term rate of return on assets.................................................................. 9.5% 1992 ----------- Assumptions: Discount rate................................................................................................ 8.75% Average increase in future compensation levels............................................................... 4.5 % Expected long-term rate of return on assets.................................................................. 9.5 %
The health care inflation rates for 1993 are assumed to be 9.5% for Medicare-eligible retirees and 12% for retirees not covered by Medicare. Both rates are assumed to decrease by 0.5% annually to an ultimate rate of 5.5% in the years 2001 and 2006, respectively. A one percentage point increase in the health care inflation rate from the assumed rates would increase the accumulated postretirement benefit obligation by approximately $37.8 million as of December 31, 1993 and would increase the aggregate of the service cost and interest cost components of postretirement benefit cost by approximately $3.8 million annually. NOTE 7. TERMINATION BENEFITS The Company offered a Voluntary Special Early Retirement Program (the 1992 VSERP) to eligible employees who retired during the period February 1, 1992 through April 1, 1992. In accordance with Statement of Financial Accounting Standards No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," the cost of termination benefits associated with the 1992 VSERP, which consisted principally of an enhanced pension benefit, was recognized in 1992 and reduced net income by $6.6 million, or 5 CENTS per common share. In April 1993, the PSC authorized BGE to amortize this charge over a five-year period for ratemaking purposes. Accordingly, BGE established a regulatory asset and recorded a corresponding credit to operating expense for this amount. The reversal of the 1992 VSERP in April 1993 increased net income by $6.6 million, or 5 CENTS per common share. The Company offered a second Voluntary Special Early Retirement Program (the 1993 VSERP) to eligible employees who retired as of February 1, 1994. The one-time cost of the 1993 VSERP consisted of enhanced pension and postretirement benefits. In addition to the 1993 VSERP, further employee reductions have been accomplished through the elimination of certain positions, and various programs have been offered to employees impacted by the eliminations. In accordance with Statement No. 88, the cost of termination benefits associated with the 1993 VSERP and various programs, which totaled $105.5 million, was recognized in 1993. The $88.3 million portion of 1993 VSERP attributable to regulated activities was deferred and will be amortized over a five-year period for ratemaking purposes, beginning in February 1994, consistent with previous rate actions of the PSC. The $17.2 million remaining portion of the cost of termination benefits was charged to expense in 1993. 47 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 8. SHORT-TERM BORROWINGS Information concerning commercial paper notes and lines of credit is set forth below. In support of the lines of credit, the Company pays commitment fees and, in some cases, maintains compensating balances which have no withdrawal restrictions. Borrowings under the lines are at the banks' prime rates, base interest rates, or at various money market rates.
1993 1992 1991 ------------- ------------- ------------- (DOLLAR AMOUNTS IN THOUSANDS) BGE'S COMMERCIAL PAPER NOTES Borrowings outstanding at December 31............................................ $ -- $ 11,900 $ 159,500 Weighted average interest rate of notes outstanding at December 31............... -- % 3.62% 4.75% Unused lines of credit supporting commercial paper notes at December 31 (a)...... $ 208,000 $ 203,000 $ 303,000 Maximum borrowings during the year............................................... 96,900 393,650 336,200 Average daily borrowings during the year (b)..................................... 10,322 98,892 210,883 Weighted average interest rate for the year (c).................................. 3.28% 4.79% 6.08% CONSTELLATION COMPANIES' LINES OF CREDIT Borrowings outstanding at December 31............................................ $ -- $ -- $ 52,670 Weighted average interest rate of borrowings outstanding at December 31.......... -- % -- % 5.94% Unused lines of credit at December 31............................................ $ 20,000 $ -- $ 8,000 Maximum borrowings during the year............................................... -- 60,670 75,000 Average daily borrowings during the year (b)..................................... -- 31,773 61,860 Weighted average interest rate for the year (c).................................. -- % 6.01% 7.19% - -------------------------- (a) BGE decreased its lines of credit supporting commercial paper notes to $143 million effective January 1, 1994. (b) The sum of dollar days of outstanding borrowings divided by the number of days in the period. (c) Total interest accrued during the period divided by average daily borrowings.
NOTE 9. LONG-TERM DEBT FIRST REFUNDING MORTGAGE BONDS OF BGE Substantially all of the principal properties and franchises owned by BGE, as well as the capital stock of Constellation Holdings, Inc., Safe Harbor Water Power Corporation, and BNG, Inc., are subject to the lien of the mortgage under which BGE's outstanding First Refunding Mortgage Bonds have been issued. On August 1 of each year, BGE is required to pay to the mortgage trustee an annual sinking fund payment equal to 1% of the largest principal amount of Mortgage Bonds outstanding under the mortgage during the preceding twelve months. Such funds are to be used, as provided in the mortgage, for the purchase and retirement by the trustee of Mortgage Bonds of any series other than the Installment Series of 2002 and 2009, the 9 1/8% Series of 1995, the 8.40% Series of 1999, the 5 1/2% Series of 2000, the 8 3/8% Series of 2001, the 7 1/4% Series of 2002, the 6 1/2% Series of 2003, the 6 1/8% Series of 2003, the 5 1/2% Series of 2004, the 6.80% Series of 2004, the 7 1/2% Series of 2007, and the 6 5/8% Series of 2008. OTHER LONG-TERM DEBT OF BGE BGE maintains revolving credit agreements that expire at various times during 1995 and 1996. Under the terms of the agreements, BGE may, at its option, obtain loans at various interest rates. A commitment fee is paid on the daily average of the unborrowed portion of the commitment. At December 31, 1993, BGE had no borrowings under these revolving credit agreements and had available $165 million of unused capacity under these agreements. Effective January 1, 1994, BGE decreased its revolving credit agreements to $125 million. The Medium-term Notes Series A mature at various dates from February 1994 through February 1996. The weighted average interest rate for notes outstanding at December 31, 1993 is 7.93%. The Medium-term Notes Series B mature at various dates from July 1998 through September 2006. The weighted average interest rate for notes outstanding at December 31, 1993 is 8.43%. The Medium-term Notes Series C mature at various dates from June 1996 through June 2003. The weighted average interest rate for notes outstanding at December 31, 1993 is 7.16%. 48 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 9. LONG-TERM DEBT (CONTINUED) The principal amounts of Installment Series Mortgage Bonds payable each year are as follows:
BONDS DUE BONDS DUE YEAR 2002 2009 - ------------------------------------------------------------------------------------ ----------- ----------- (IN THOUSANDS) 1994................................................................................ $ 430 1995 through 1997................................................................... 605 1998 and 1999....................................................................... 690 2000 and 2001....................................................................... 865 2002................................................................................ 6,725 2005 through 2008................................................................... $ 3,250 2009................................................................................ 42,000
LONG-TERM DEBT OF CONSTELLATION COMPANIES The mortgage and construction loans and other collateralized notes have varying terms. Of the $151.2 million of variable rate notes, $51.1 million requires periodic interest only payments with various maturities from September 1995 through March 1996, and $100.1 million requires periodic payment of principal and interest with various maturities from January 1995 through January 2009. The $6.5 million, 7.73% mortgage note requires quarterly principal and interest payments through March 15, 2009. The unsecured notes outstanding as of December 31, 1993 mature in accordance with the following schedule:
(IN THOUSANDS) 8.35%, due August 28, 1995.................................................................... $ 20,000 8.71%, due August 28, 1996.................................................................... 23,000 6.19%, due September 9, 1996.................................................................. 10,000 8.93%, due August 28, 1997.................................................................... 52,000 6.65%, due September 9, 1997.................................................................. 15,000 8.23%, due October 15, 1997................................................................... 30,000 7.05%, due April 22, 1998..................................................................... 25,000 7.06%, due September 9, 1998.................................................................. 20,000 8.48%, due October 15, 1998................................................................... 75,000 7.30%, due April 22, 1999..................................................................... 90,000 8.73%, due October 15, 1999................................................................... 15,000 7.55%, due April 22, 2000..................................................................... 35,000 7.43%, due September 9, 2000.................................................................. 30,000 -------------- Total......................................................................................... $ 440,000 -------------- --------------
WEIGHTED AVERAGE INTEREST RATES FOR VARIABLE RATE DEBT The weighted average interest rates for variable rate debt during 1993 and 1992 were as follows:
1993 1992 ----------- ----------- BGE Loans under revolving credit agreements................................................ -- % 4.23% Floating rate notes Series II.......................................................... -- 7.90 Pollution control loan................................................................. 2.39 2.90 Port facilities loan................................................................... 2.53 3.04 Adjustable rate pollution control loan................................................. 3.00 4.13 Economic development loan.............................................................. 2.49 3.11 Constellation Companies Mortgage and construction loans and other collateralized notes......................... 6.26 6.74 Loans under credit agreements.......................................................... 5.94 6.15
49 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 9. LONG-TERM DEBT (CONTINUED) AGGREGATE MATURITIES The combined aggregate maturities and sinking fund requirements for all of the Company's long-term borrowings for each of the next five years are as follows:
CONSTELLATION YEAR BGE COMPANIES - --------------------------------------------------------------------------------- ----------- ------------ (IN THOUSANDS) 1994............................................................................. $ 32,728 $ 8,788 1995............................................................................. 218,429 81,260 1996............................................................................. 72,330 77,213 1997............................................................................. 80,754 112,359 1998............................................................................. 84,112 128,355
NOTE 10. REDEEMABLE PREFERENCE STOCK The 6.95%, 1987 Series and the 7.80%, 1989 Series are subject to mandatory redemption in their entirety at par on October 1, 1995 and July 1, 1997, respectively. The following series are subject to an annual mandatory redemption of the number of shares shown below at par beginning in the year shown below. At BGE's option, an additional number of shares, not to exceed the same number as are mandatory, may be redeemed at par in any year, commencing in the same year in which the mandatory redemption begins. The 8.25%, 1989 Series, the 8.625%, 1990 Series, and the 7.85%, 1991 Series listed below are not redeemable except through operation of a sinking fund.
BEGINNING SERIES SHARES YEAR - ------------------------------------------------------------------------------------- ---------- ----------- 7.50%, 1986 Series................................................................... 15,000 1992 6.75%, 1987 Series................................................................... 15,000 1993 8.25%, 1989 Series................................................................... 100,000 1995 8.625%, 1990 Series.................................................................. 130,000 1996 7.85%, 1991 Series................................................................... 70,000 1997
The combined aggregate redemption requirements for all series of redeemable preference stock for each of the next five years are as follows:
YEAR - ---------------------------------------------------------------------------------------------- (IN THOUSANDS) 1994.......................................................................................... $ 3,000 1995.......................................................................................... 63,000 1996.......................................................................................... 26,000 1997.......................................................................................... 83,000 1998.......................................................................................... 33,000
With regard to payment of dividends or assets available in the event of liquidation, preferred stock ranks prior to preference and common stock; all issues of preference stock, whether subject to mandatory redemption or not, rank equally; and all preference stock ranks prior to common stock. NOTE 11. LEASES The Company, as lessee, contracts for certain facilities and equipment under lease agreements with various expiration dates and renewal options. Consistent with the regulatory treatment, BGE lease payments are charged to expense. Lease expense, which is comprised primarily of operating leases, totaled $13.8 million, $14 million, and $12.6 million for the years ended 1993, 1992, and 1991, respectively. 50 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 11. LEASES (CONTINUED) The future minimum lease payments at December 31, 1993 for long-term noncancelable operating leases are as follows:
YEAR - ---------------------------------------------------------------------------------------------- (IN THOUSANDS) 1994.......................................................................................... $ 4,439 1995.......................................................................................... 4,185 1996.......................................................................................... 3,627 1997.......................................................................................... 2,755 1998.......................................................................................... 1,751 Thereafter.................................................................................... 2,770 -------------- Total minimum lease payments.................................................................. $ 19,527 -------------- --------------
Certain of the Constellation Companies, as lessor, have entered into operating leases for office and retail space. These leases expire over periods ranging from 1 to 23 years, with options to renew. The net book value of property under operating leases was $187 million at December 31, 1993. The future minimum rentals to be received under operating leases in effect at December 31, 1993 are as follows:
YEAR - ---------------------------------------------------------------------------------------------- (IN THOUSANDS) 1994.......................................................................................... $ 16,685 1995.......................................................................................... 15,222 1996.......................................................................................... 13,826 1997.......................................................................................... 12,398 1998.......................................................................................... 10,744 Thereafter.................................................................................... 62,888 -------------- Total minimum rentals......................................................................... $ 131,763 -------------- --------------
NOTE 12. TAXES OTHER THAN INCOME TAXES Taxes other than income taxes were as follows:
YEAR ENDED DECEMBER 31, ------------------------------------- 1993 1992 1991 ----------- ----------- ----------- (DOLLAR AMOUNTS IN THOUSANDS) Real and personal property............................................................... $ 107,958 $ 100,419 $ 89,379 Public service company franchise......................................................... 48,693 45,654 46,041 Social security.......................................................................... 35,724 34,911 33,121 Other.................................................................................... 9,836 9,355 9,026 ----------- ----------- ----------- Total taxes other than income taxes...................................................... 202,211 190,339 177,567 Amounts included above charged to accounts other than taxes.............................. (7,379) (7,335) (6,786) ----------- ----------- ----------- Taxes other than income taxes per Consolidated Statements of Income...................... $ 194,832 $ 183,004 $ 170,781 ----------- ----------- ----------- ----------- ----------- -----------
NOTE 13. COMMITMENTS, GUARANTEES, AND CONTINGENCIES COMMITMENTS BGE has made substantial commitments in connection with its construction program for 1994 and subsequent years. In addition, BGE has entered into two long-term contracts for the purchase of electric generating 51 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 13. COMMITMENTS, GUARANTEES, AND CONTINGENCIES (CONTINUED) capacity and energy. The contracts expire in 2001 and 2013. Total payments under these contracts were $68.7 million, $60.6 million, and $30 million during 1993, 1992, and 1991, respectively. At December 31, 1993, the estimated future payments for capacity and energy that BGE is obligated to buy under these contracts are as follows:
YEAR - ---------------------------------------------------------------------------------------------- (IN THOUSANDS) 1994.......................................................................................... $ 63,675 1995.......................................................................................... 71,884 1996.......................................................................................... 71,051 1997.......................................................................................... 67,496 1998.......................................................................................... 67,556 Thereafter.................................................................................... 415,736 -------------- Total payments................................................................................ $ 757,398 -------------- --------------
Certain of the Constellation Companies have committed to contribute additional capital and to make additional loans to certain affiliates, joint ventures, and partnerships in which they have an interest. As of December 31, 1993, the total amount of investment requirements committed to by the Constellation Companies is $44 million. GUARANTEES BGE has agreed to guarantee two-thirds of certain indebtedness incurred by Safe Harbor Water Power Corporation. The amount of such indebtedness totals $40 million, of which $26.7 million represents BGE's share of the guarantee. BGE believes that the risk of material loss on the loans guaranteed is minimal. As of December 31, 1993, the total outstanding loans and letters of credit of certain power generation and real estate projects guaranteed by the Constellation Companies were $50 million. Also, the Constellation Companies have agreed to guarantee certain other borrowings of various power generation and real estate projects. The Company believes that the risk of material loss on the loans guaranteed and performance guarantees is minimal. ENVIRONMENTAL MATTERS The Clean Air Act of 1990 (the Act) contains provisions designed to reduce sulfur dioxide and nitrogen oxide emissions from electric generating stations in two separate phases. Under Phase I of the Act, which must be implemented by 1995, BGE expects to incur expenditures of approximately $55 million, most of which is attributable to its portion of the cost of installing a flue gas desulfurization system at the Conemaugh generating station, in which BGE owns a 10.56% interest. BGE is currently examining what actions will be required in order to comply with Phase II of the Act, which must be implemented by 2000. However, BGE anticipates that compliance will be attained by some combination of fuel switching, flue gas desulfurization, unit retirements, or allowance trading. At this time, plans for complying with nitrogen oxide (NOx) control requirements under the Act are less certain because all implementation regulations have not yet been finalized by the government. It is expected that by the year 2000 these regulations will require additional NOx controls for ozone attainment at BGE's generating plants and at other BGE facilities. The controls will result in additional expenditures that are difficult to predict prior to the issuance of such regulations. Based on existing and proposed ozone nonattainment regulations, BGE currently estimates that the NOx controls at BGE's generating plants will cost approximately $70 million. BGE is currently unable to predict the cost of compliance with the additional requirements at other BGE facilities. BGE has been notified by the Environmental Protection Agency (EPA) and several state agencies that it is being considered a potentially responsible party with respect to the cleanup of certain environmentally contaminated sites owned and operated by third parties. Although the cleanup costs for certain environmentally contaminated sites could be significant, BGE believes that the resolution of these matters will not have a material effect on its financial position or results of operations. Also, BGE is coordinating investigation of several former gas manufacturing plant sites, including exploration of corrective action options to remove coal tar. However, no formal legal proceedings have been instituted. In 1993, BGE accrued a liability of approximately $25.4 million for estimated future environmental costs at these sites. Based on previous actions of the PSC, BGE has deferred these estimated future costs, as well as actual costs 52 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 13. COMMITMENTS, GUARANTEES, AND CONTINGENCIES (CONTINUED) which have been incurred to date, as a regulatory asset (see Note 5). The technology for cleaning up such sites is still developing, and potential remedies for these sites have not been identified. Cleanup costs in excess of the amounts recognized, which could be significant in total, cannot presently be estimated. NUCLEAR INSURANCE An accident or an extended outage at either unit of the Calvert Cliffs Nuclear Power Plant could have a substantial adverse effect on BGE. The primary contingencies resulting from an incident at the Calvert Cliffs plant would involve the physical damage to the plant, the recoverability of replacement power costs and BGE's liability to third parties for property damage and bodily injury. Although BGE maintains the various insurance policies currently available to provide coverage for portions of these contingencies, BGE does not consider the available insurance to be adequate to cover the costs that could result from a major accident or an extended outage at either of the Calvert Cliffs units. In addition, in the event of an incident at any commercial nuclear power plant in the country, BGE could be assessed for a portion of any third party claims associated with the incident. Under the provisions of the Price Anderson Act, the limit for third party claims from a nuclear incident is $9.4 billion. If third party claims relating to such an incident exceed $200 million (the amount of primary insurance), BGE's share of the total liability for third party claims could be up to $159 million per incident, that would be payable at a rate of $20 million per year. BGE and other operators of commercial nuclear power plants in the United States are required to purchase insurance to cover claims of certain nuclear workers. Other non-governmental commercial nuclear facilities may also purchase such insurance. Coverage of up to $400 million is provided for claims against BGE or others insured by these policies for radiation injuries. If certain claims were made under these policies, BGE and all policyholders could be assessed, with BGE's share being up to $6.2 million in any one year. For physical damage to Calvert Cliffs, BGE has $2.7 billion of property insurance, including $1.4 billion from an industry mutual insurance company. If accidents at any insured plants cause a shortfall of funds at the industry mutual, BGE and all policyholders could be assessed, with BGE's share being up to $14.6 million. If an outage at Calvert Cliffs is caused by an insured physical damage loss and lasts more than 21 weeks, BGE has up to $426 million per unit of insurance, provided by a different industry mutual insurance company for replacement power costs. This amount can be reduced by up to $85 million per unit if an outage to both units at Calvert Cliffs is caused by a singular insured physical damage loss. If an outage at any insured plant causes a short-fall of funds at the industry mutual, BGE and all policyholders could be assessed, with BGE's share being up to $9.4 million. RECOVERABILITY OF ELECTRIC FUEL COSTS By statute, actual electric fuel costs are recoverable so long as the PSC finds that BGE demonstrates that, among other things, it has maintained the productive capacity of its generating plants at a reasonable level. The PSC and Maryland's highest appellate court have interpreted this as permitting a subjective evaluation of each unplanned outage at BGE's generating plants to determine whether or not BGE had implemented all reasonable and cost effective maintenance and operating control procedures appropriate for preventing the outage. Effective January 1, 1987, the PSC authorized the establishment of the Generating Unit Performance Program (GUPP) to measure, annually, utility compliance with maintaining the productive capacity of generating plants at reasonable levels by establishing a system-wide generating performance target and individual performance targets for each base load generating unit. In future fuel rate hearings, actual generating performance after adjustment for planned outages will be compared to the system-wide target and, if met, should signify that BGE has complied with the requirements of Maryland law. Failure to meet the system-wide target will result in review of each units adjusted actual generating performance versus its performance target in determining compliance with the law and the basis for possibly imposing a penalty on BGE. Parties to fuel rate hearings may still question the prudence of BGE's actions or inactions with respect to any given generating plant outage, which could result in the disallowance of replacement energy costs by the PSC. Since the two units at BGE's Calvert Cliffs Nuclear Power Plant utilize BGE's lowest cost fuel, replacement energy costs associated with outages at these units can be significant. BGE 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. In October 1988, BGE filed its first fuel rate application for a change in its electric fuel rate under the GUPP program. The resultant case before the PSC covers BGE's operating performance in calendar year 1987, and BGE's filing demonstrated that it met the system-wide and individual nuclear plant performance targets for 53 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 13. COMMITMENTS, GUARANTEES, AND CONTINGENCIES (CONTINUED) 1987. In November 1989, testimony was filed on behalf of Maryland People's Counsel alleging that seven outages at the Calvert Cliffs plant in 1987 were due to management imprudence and that the replacement energy costs associated with those outages should be disallowed by the Commission. Total replacement energy costs associated with the 1987 outages were approximately $33 million. In May 1989, BGE filed its fuel rate case in which 1988 performance was to be examined. BGE met the system-wide and nuclear plant performance targets in 1988. People's Counsel alleges that BGE imprudently managed several outages at Calvert Cliffs, and BGE estimates that the total replacement energy costs associated with these 1988 outages were approximately $2 million. On November 14, 1991, a Hearing Examiner at the PSC issued a proposed Order, which became final on December 17, 1991 and concluded that no disallowance was warranted. The Hearing Examiner found that BGE maintained the productive capacity of the Plant at a reasonable level, noting that it produced a near record amount of power and exceeded the GUPP standard. Based on this record, the Order concluded there was sufficient cause to excuse any avoidable failures to maintain productive capacity at higher levels. During 1989, 1990, and 1991, BGE experienced extended outages at Calvert Cliffs. In the Spring of 1989, a leak was discovered around the Unit 2 pressurizer heater sleeves during a refueling outage. BGE shut down Unit 1 as a precautionary measure on May 6, 1989 to inspect for similar leaks and none were found. However, Unit 1 was out of service for the remainder of 1989 and 285 days of 1990 to undergo maintenance and modification work to enhance the reliability of various safety systems, to repair equipment, and to perform required periodic surveillance tests. Unit 2, which returned to service on May 4, 1991, remained out of service for the remainder of 1989, 1990, and the first part of 1991 to repair the pressurizer, perform maintenance and modification work, and complete the refueling. The replacement energy costs associated with these extended outages for both units at Calvert Cliffs, concluding with the return to service of Unit 2, are estimated to be $458 million. In a December 1990 order issued by the PSC in a BGE base rate proceeding, the PSC found that certain operations and maintenance expenses incurred at Calvert Cliffs during the test year should not be recovered from ratepayers. The PSC found that this work, which was performed during the 1989-1990 Unit 1 outage and fell within the test year, was avoidable and caused by BGE actions which were deficient. The Commission noted in the order that its review and findings on these issues pertain to the reasonableness of BGE's test-year operations and maintenance expenses for purposes of setting base rates and not to the responsibility for replacement power costs associated with the outages at Calvert Cliffs. The PSC stated that its decision in the base rate case will have no RES JUDICATA (binding) effect in the fuel rate proceeding examining the 1989-1991 outages. The work characterized as avoidable significantly increased the duration of the Unit 1 outage. Despite the PSC's statement regarding no binding effect, BGE recognizes that the views expressed by the PSC make the full recovery of all of the replacement energy costs associated with the Unit 1 outage doubtful. Therefore, in December 1990, BGE recorded a provision of $35 million against the possible disallowance of such costs. BGE cannot determine whether replacement energy costs may be disallowed in the present fuel rate proceedings in excess of the provision, but such amounts could be material. NOTE 14. FAIR VALUE OF FINANCIAL INSTRUMENTS The following table presents the carrying amount and fair value of financial instruments included in the Consolidated Balance Sheets.
AT DECEMBER 31, ---------------------------------------------------------- 1993 1992 ---------------------------- ---------------------------- CARRYING CARRYING AMOUNT FAIR VALUE AMOUNT FAIR VALUE ------------- ------------- ------------- ------------- (IN THOUSANDS) Current assets..................................................... $ 496,919 $ 496,919 $ 408,790 $ 408,790 Investments and other assets....................................... 125,046 129,752 93,834 97,135 Current liabilities................................................ 443,968 443,968 649,650 649,650 Capitalization..................................................... 3,165,644 3,303,615 2,772,450 2,871,291
The carrying amount of current assets and current liabilities approximates fair value because of the short maturity of these instruments. The fair value of investments and other assets is based on quoted market prices where available. Certain investments with a carrying amount of $70 million at December 31, 1993 and $71 million at December 31, 1992 are excluded from the amounts shown in investments and other assets because it was not practicable to 54 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED) NOTE 14. FAIR VALUE OF FINANCIAL INSTRUMENTS (CONTINUED) determine their fair values. These investments include partnership investments in public and private equity and debt securities, partnership investments in solar powered energy production facilities, and investments in stock trusts. Financial instruments included in capitalization are long-term debt and redeemable preference stock. The fair value of fixed-rate long-term debt and redeemable preference stock is estimated using quoted market prices where available, or by discounting remaining cash flows at the current market rate. The carrying amount of variable-rate long-term debt approximates fair value. BGE and the Constellation Companies have loan guarantees totalling $26.7 million and $36 million, respectively, at December 31, 1993 and $30 and $38 million, respectively, at December 31, 1992 for which it is not practicable to determine fair value. It is not anticipated that these loan guarantees will need to be funded. NOTE 15. QUARTERLY FINANCIAL DATA (UNAUDITED) The following data are unaudited but, in the opinion of Management, include all adjustments necessary for a fair presentation. BGE's 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 be indicative of overall trends and changes in operations.
QUARTER ENDED ---------------------------------------------------- YEAR ENDED MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 DECEMBER 31 ----------- ----------- ------------ ------------ ------------- (IN THOUSANDS, EXCEPT PER-SHARE AMOUNTS) 1993 Revenues................................................. $ 683,825 $ 564,721 $ 774,064 $ 646,104 $ 2,668,714 Income from operations................................... 136,094 107,387 287,461 90,058 621,000 Net income............................................... 65,796 55,876 157,058 31,136 309,866 Earnings applicable to common stock...................... 55,276 45,300 146,511 20,940 268,027 Earnings per share of common stock....................... 0.38 0.31 1.01 0.14 1.85 ----------- ----------- ------------ ------------ ------------- ----------- ----------- ------------ ------------ ------------- 1992 Revenues................................................. $ 669,253 $ 540,895 $ 677,059 $ 604,136 $ 2,491,343 Income from operations................................... 127,121 91,309 222,627 94,288 535,345 Net income............................................... 59,254 38,049 124,620 42,424 264,347 Earnings applicable to common stock...................... 48,680 27,475 114,047 31,898 222,100 Earnings per share of common stock....................... 0.37 0.20 0.84 0.22 1.63 ----------- ----------- ------------ ------------ ------------- ----------- ----------- ------------ ------------ -------------
RESULTS FOR THE SECOND QUARTER OF 1993 REFLECT THE REVERSAL OF THE COST OF THE TERMINATION BENEFITS ASSOCIATED WITH THE 1992 VOLUNTARY SPECIAL EARLY RETIREMENT PROGRAM (SEE NOTE 7). RESULTS FOR THE THIRD QUARTER OF 1993 REFLECT THE EFFECTS OF THE OMNIBUS BUDGET RECONCILIATION ACT OF 1993. RESULTS FOR THE FOURTH QUARTER OF 1993 REFLECT THE COST OF CERTAIN TERMINATION BENEFITS (SEE NOTE 7). RESULTS FOR THE FIRST AND THIRD QUARTERS OF 1992 REFLECT THE COST OF TERMINATION BENEFITS ASSOCIATED WITH THE 1992 VOLUNTARY SPECIAL EARLY RETIREMENT PROGRAM (SEE NOTE 7). THE SUM OF THE QUARTERLY EARNINGS PER SHARE AMOUNTS MAY NOT EQUAL THE TOTAL FOR THE YEAR DUE TO CHANGES IN THE AVERAGE NUMBER OF SHARES OUTSTANDING THROUGHOUT THE YEAR. 55 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item with respect to directors is set forth on pages 2 through 4 under "Item 1. Election of 14 Directors" in the Proxy Statement and is incorporated herein by reference. The information required by this item with respect to executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of Regulation S-K, set forth in Item 10 of Part I of this Form 10-K under "Executive Officers of the Registrant." ITEM 11. EXECUTIVE COMPENSATION The information required by this item is set forth on pages 7 through 11 under "Item 1. Election of 14 Directors -- Compensation of Executive Officers by the Company" in the Proxy Statement and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is set forth on page 6 under "Item 1. Election of 14 Directors -- Security Ownership of Directors and Executive Officers" in the Proxy Statement and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this item is set forth on page 5 under "Item 1. Election of 14 Directors -- Certain Relationships and Transactions" in the Proxy Statement and is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as a part of this Report: 1. Financial Statements: Auditors' Report dated January 21, 1994 of Coopers & Lybrand, Independent Auditors Consolidated Statements of Income for three years ended December 31, 1993 Consolidated Balance Sheets at December 31, 1993 and December 31, 1992 Consolidated Statements of Cash Flows for three years ended December 31, 1993 Consolidated Statements of Common Shareholders' Equity for three years ended December 31, 1993 Consolidated Statements of Capitalization at December 31, 1993 and December 31, 1992 Consolidated Statements of Income Taxes for three years ended December 31, 1993 Notes to Consolidated Financial Statements 2. Financial Statement Schedules: Schedule V -- Property, Plant and Equipment Schedule VI -- Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment Schedule VII -- Guarantees of Securities of Other Issuers Schedule VIII -- Valuation and Qualifying Accounts
Schedules other than those listed above are omitted as not applicable or not required. 56 3. Exhibits Required by Item 601 of Regulation S-K Including Each Management Contract or Compensatory Plan or Arrangement Required to be Filed as an Exhibit.
EXHIBIT NUMBER - ------- *3(a) -- Charter of BGE, restated as of October 13, 1993. (Designated as Exhibit No. 3(b) in Form 10-Q dated November 12, 1993, File No. 1-1910.) *3(b) -- By-Laws of BGE, as amended to March 1, 1993. (Designated as Exhibit No. 3(c) in Form 10-K Annual Report for 1992, File No. 1-1910.) 4(a) -- Indenture and Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN ---------------------------------------------------------------------------------------- EXHIBIT DATED FILE NO. NUMBER - ------------------------- ----------- -------------- *February 1, 1919 2-2640 B-3 *December 1, 1920 2-2640 B-4 *October 1, 1921 2-2640 B-5 *September 1, 1922 2-2640 B-6 *June 1, 1925 2-2640 B-7 *March 1, 1929 2-2640 B-8 *July 1, 1930 2-2640 B-9 *June 1, 1931 2-2640 B-10 *November 1, 1934 2-2640 B-11 *May 1, 1935 2-2640 B-12 *July 1, 1935 2-2640 B-13 *December 1, 1936 2-3708 B-14 *June 15, 1938 1-1910-2 (Form 8-K Report for June 1938) 1 *June 1, 1939 2-4625 B-15 *January 1, 1941 2-6296 B-16 *April 1, 1946 2-7020 7-17 *March 1, 1948 1-1910-2 (Form 8-K Report for March 1948) 1 *December 19, 1949 2-8740 7-19 *December 20, 1949 2-8740 7-20 *June 15, 1950 2-8740 7-21 *January 15, 1951 2-9916 4-30 *June 1, 1953 2-9916 4-33 *July 15, 1954 2-11676 4-3 *December 1, 1955 2-13127 4-3 *March 1, 1958 1-1910-P (Form 8-A dated March 12, 1958) 1-2 *June 1, 1960 1-1910 (Form 8-K for June 1960) 1 *July 15, 1962 1-1910 (Form 8-K for July 1962) 1 *July 15, 1964 2-23763 2-3 *July 26, 1965 2-24800 2-3 *April 15, 1966 2-26278 4-3 *June 16, 1967 2-27005 2-3 *August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1 *December 15, 1968 1-1910 (Form 10-K Annual Report for 1968) D-1 *September 15, 1969 2-35453 2-6 *April 1, 1970 1-1910 (Form 8-A dated March 30, 1970) 2(b) *July 1, 1970 1-1910 (Form 8-A dated June 30, 1970) 2(c) *September 15, 1970 2-39561 2-4 *April 15, 1971 2-41252 2-4 *September 1, 1971 2-42574 2-4 *January 1, 1972 1-1910 (Form 10-K Annual Report for 1971) A-2 *July 1, 1972 2-45452 2-3
57
DESIGNATED IN ---------------------------------------------------------------------------------------- EXHIBIT DATED FILE NO. NUMBER - ------------------------- ----------- -------------- *September 15, 1972 1-1910 (Form 10-K Annual Report for 1972) A-1 *August 15, 1973 1-1910 (Form 8-K Report for August 1973) 3-4 *February 1, 1974 1-1910 (Form 10-K Annual Report for 1973) A-1 *July 1, 1974 1-1910 (Form 8-A dated July 5, 1974) 2(b) *September 15, 1974 1-1910 (Form 8-A dated September 13, 1974) 2(b) *August 1, 1975 1-1910 (Form 8-A dated August 5, 1975) 2(b) *September 15, 1976 1-1910 (Form 8-A dated September 24, 1976) 2(b) *July 15, 1977 2-59772 2-3 (3 Indentures) *September 15, 1977 1-1910 (Form 8-A dated September 23, 1977) 2(c) *July 1, 1978 1-1910 (Form 8-A dated June 30, 1978) 2(b) *September 15, 1979 1-1910 (Form 10-Q dated November 14, 1979) 2-5 and 2-6 (2 Indentures) *September 15, 1980 1-1910 (Form 8-A dated September 12, 1980) 2(b) *July 8, 1981 1-1910 (Form 10-Q dated August 17, 1981) 20-2(c) *October 1, 1981 1-1910 (Form 8-A dated September 29, 1981) 2(b) *July 15, 1982 1-1910 (Form 8-A dated July 28, 1982) 2(b) *March 1, 1986 1-1910 (Form 8-A dated February 24, 1986, as amended by Form 8 2 dated March 3, 1986) *June 15, 1987 1-1910 (Form 8-K Report for July 29, 1987) 4(a) *October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a) *October 15, 1990 33-38803 (Form S-3 Registration) 4(a) *August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i) *January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii) *July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a) *February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i) *March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii) *March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii) *April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4 *July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a) *July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b) *October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4 March 15, 1994 (Filed Herewith) 4(a)
*4(b) -- Indenture dated July 1, 1985, between BGE and Mercantile-Safe Deposit and Trust Company, Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).) *10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan. (Designated as Exhibit No. 10(a) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) 10(b) -- Summary of amendment to the Baltimore Gas and Electric Company Executive Benefits Plan. *10(c) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) *10(d) -- Baltimore Gas and Electric Company Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) *10(e) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Executive Officers. (Designated as Exhibit No. 10(d) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.)
58
EXHIBIT NUMBER - ----------- 10(f) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Non- Employee Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for Non-Employee Directors). 10(g) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. 10(h) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. *10(i) -- Constellation Holdings, Inc., Summary of Executive Benefits Plan. (Designated as Exhibit No. 10(f) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) *10(j) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) 10(k) -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc. 12 -- Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. 21 -- Subsidiaries of the Registrant. 23 -- Consent of Coopers & Lybrand, Independent Auditors (see page 73 in this Form 10-K). *99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.) *99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland. (Designated as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31, 1987, File No. 1-1910.) - -------------------------- *Incorporated by Reference.
(b) Reports on Form 8-K: None 59 SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
BALANCE, END OF YEAR ---------------------------- 1993 1992 ------------- ------------- (IN THOUSANDS) UTILITY PLANT Electric Plant in Service Intangible......................................................................... $ 12,017 $ 10,573 Production......................................................................... 3,409,980 3,307,453 Transmission....................................................................... 437,907 411,891 Distribution....................................................................... 1,726,010 1,634,357 General............................................................................ 127,345 110,316 Property Under Capital Leases........................................................ -- -- Plant Held for Future Use............................................................ 22,324 19,743 Construction Work in Progress........................................................ 385,207 273,140 Nuclear Fuel......................................................................... 856,406 809,077 ------------- ------------- Total............................................................................ 6,977,196 6,576,550 ------------- ------------- Gas Plant in Service Intangible......................................................................... 585 604 Production......................................................................... 15,710 15,101 Storage............................................................................ 23,547 21,519 Distribution....................................................................... 514,230 485,308 General............................................................................ 3,869 3,526 Construction Work in Progress........................................................ 26,582 18,632 ------------- ------------- Total............................................................................ 584,523 544,690 ------------- ------------- Common Plant in Service Intangible......................................................................... 70,892 69,176 General............................................................................ 416,848 399,087 Property Under Capital Leases........................................................ -- -- Plant Held for Future Use............................................................ 1,743 1,743 Construction Work in Progress........................................................ 24,651 17,136 ------------- ------------- Total............................................................................ 514,134 487,142 ------------- ------------- Total Utility Plant............................................................ 8,075,853 7,608,382 ------------- ------------- OTHER PHYSICAL PROPERTY Land, Aquaculture Facility, Merchandising Facilities, and Capital Leases............... 12,602 12,398 ------------- ------------- Total Property, Plant and Equipment............................................ $ 8,088,455 $ 7,620,780 ------------- ------------- ------------- ------------- DIVERSIFIED BUSINESSES Constellation Holdings, Inc............................................................ $ 518,274 $ 512,565 ------------- ------------- ------------- ------------- BNG, Inc............................................................................... $ 6,637 $ 8,848 ------------- ------------- ------------- ------------- 1991 ------------- UTILITY PLANT Electric Plant in Service Intangible......................................................................... $ 10,240 Production......................................................................... 3,217,154 Transmission....................................................................... 382,185 Distribution....................................................................... 1,503,798 General............................................................................ 101,974 Property Under Capital Leases........................................................ 48 Plant Held for Future Use............................................................ 16,247 Construction Work in Progress........................................................ 273,921 Nuclear Fuel......................................................................... 769,591 ------------- Total............................................................................ 6,275,158 ------------- Gas Plant in Service Intangible......................................................................... 487 Production......................................................................... 14,714 Storage............................................................................ 20,738 Distribution....................................................................... 455,695 General............................................................................ 3,316 Construction Work in Progress........................................................ 15,428 ------------- Total............................................................................ 510,378 ------------- Common Plant in Service Intangible......................................................................... 69,569 General............................................................................ 376,602 Property Under Capital Leases........................................................ 29 Plant Held for Future Use............................................................ 1,743 Construction Work in Progress........................................................ 18,416 ------------- Total............................................................................ 466,359 ------------- Total Utility Plant............................................................ 7,251,895 ------------- OTHER PHYSICAL PROPERTY Land, Aquaculture Facility, Merchandising Facilities, and Capital Leases............... 10,797 ------------- Total Property, Plant and Equipment............................................ $ 7,262,692 ------------- ------------- DIVERSIFIED BUSINESSES Constellation Holdings, Inc............................................................ $ 494,571 ------------- ------------- BNG, Inc............................................................................... $ 8,842 ------------- -------------
The information required by Columns B, C, D, and E is omitted because neither the total additions nor the total deductions during the periods amounted to more than 10% of the closing balances of total property, plant and equipment. Additions and retirements of property, plant and equipment for 1991 through 1993 are set forth below.
1993 1992 ---------- ---------- (IN THOUSANDS) Additions, at cost Other Than Nuclear Fuel........................................................................ 470,476 382,501 Nuclear Fuel................................................................................... 47,329 39,486 Other............................................................................................ (206) 901 Retirements, at cost or estimated amounts approximately book cost................................ 49,924 64,800 1991 ------------ Additions, at cost Other Than Nuclear Fuel........................................................................ 456,244 Nuclear Fuel................................................................................... 1,854 Other............................................................................................ 97,633* Retirements, at cost or estimated amounts approximately book cost................................ 88,884** - -------------------------- *The 1991 other includes $57,780,000 of AFC resulting from the adoption by the Company of Statement of Financial Accounting Standards No. 109 and $40,259,000 of deferred income taxes on AFC in connection with adopting Statement of Financial Accounting Standards No. 96. **The 1991 retirements reflect the $46,031,000 retirement of the Riverside SNG Plant.
60 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR 1993
COLUMN C COLUMN E COLUMN B ----------- -------------- ------------- ADDITIONS COLUMN D OTHER CHANGES COLUMN F COLUMN A BALANCE AT CHARGED TO ----------- -- ADD ------------- - ----------------------------------------------------- BEGINNING OF COSTS AND RETIREMENTS (DEDUCT) -- BALANCE AT DESCRIPTION PERIOD EXPENSES (DEDUCT) DESCRIBE END OF PERIOD - ----------------------------------------------------- ------------- ----------- ----------- -------------- ------------- (IN THOUSANDS) Accumulated Provision for Depreciation of Utility Plant: Electric........................................... $ 1,709,591 $ 183,816 $ (27,643) $ (5,051)(A) $ 1,860,713 Gas................................................ 163,161 19,498 (4,682) (658)(A) 177,319 Common............................................. 86,732 21,232 (15,671) 3,112(A) 95,405 ------------- ----------- ----------- ------- ------------- Total............................................ 1,959,484 224,546 (47,996) (2,597) 2,133,437 ------------- ----------- ----------- ------- ------------- Accumulated Provision for Amortization of Utility Plant............................................... 20,877 8,959 -- (1,289)(B) 28,547 ------------- ----------- ----------- ------- ------------- Total Accumulated Provision for Depreciation and Amortization of Utility Plant....................... $ 1,980,361 $ 233,505 $ (47,996) $ (3,886) $ 2,161,984 ------------- ----------- ----------- ------- ------------- ------------- ----------- ----------- ------- ------------- Accumulated Provision for Amortization of Nuclear Fuel Assemblies..................................... $ 708,977 ------------- ------------- Accumulated Provision for Amortization of Other Physical Property................................... $ 2,471 ------------- ------------- Accumulated Provision for Amortization and Depreciation of Property of: Constellation Holdings, Inc........................ $ 27,901 ------------- ------------- BNG, Inc........................................... $ 3,312 ------------- ------------- - -------------------------- (A) Represents principally net cost of removal and salvage applicable to retired property. (B) Represents principally write-off of equipment which is fully amortized.
NOTE: For a statement of the Company's depreciation policy, see NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS. The Company's Accumulated Provision for Depreciation is not segregated according to the "Classification" of property shown under "Plant in Service" in Schedule V. 61 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR 1992
COLUMN E COLUMN C -------------- COLUMN B ----------- OTHER CHANGES ------------- ADDITIONS COLUMN D -- COLUMN F COLUMN A BALANCE AT CHARGED TO ----------- ADD (DEDUCT) ------------- - ----------------------------------------------------- BEGINNING OF COSTS AND RETIREMENTS -- BALANCE AT DESCRIPTION PERIOD EXPENSES (DEDUCT) DESCRIBE END OF PERIOD - ----------------------------------------------------- ------------- ----------- ----------- -------------- ------------- (IN THOUSANDS) Accumulated Provision for Depreciation of Utility Plant: Electric........................................... $ 1,579,290 $ 173,461 $ (41,968) $ (1,192)(A) $ 1,709,591 Gas................................................ 148,002 18,517 (2,556) (802)(A) 163,161 Common............................................. 79,341 22,107 (16,623) 1,907(A) 86,732 ------------- ----------- ----------- ------- ------------- Total............................................ 1,806,633 214,085 (61,147) (87) 1,959,484 ------------- ----------- ----------- ------- ------------- Accumulated Provision for Amortization of Utility Plant............................................... 15,747 8,587 -- (3,457)(B) 20,877 ------------- ----------- ----------- ------- ------------- Total Accumulated Provision for Depreciation and Amortization of Utility Plant....................... $ 1,822,380 $ 222,672 $ (61,147) $ (3,544) $ 1,980,361 ------------- ----------- ----------- ------- ------------- ------------- ----------- ----------- ------- ------------- Accumulated Provision for Amortization of Nuclear Fuel Assemblies..................................... $ 659,697 ------------- ------------- Accumulated Provision for Amortization of Other Physical Property................................... $ 2,341 ------------- ------------- Accumulated Provision for Amortization and Depreciation of Property of: Constellation Holdings, Inc........................ $ 26,998 ------------- ------------- BNG, Inc. ......................................... $ 4,927 ------------- ------------- - -------------------------- (A) Represents principally net cost of removal and salvage applicable to retired property. (B) Represents principally write-off of equipment which is fully amortized.
NOTE: For a statement of the Company's depreciation policy, see NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS. The Company's Accumulated Provision for Depreciation is not segregated according to the "Classification" of property shown under "Plant in Service" in Schedule V. 62 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR 1991
COLUMN E COLUMN C -------------- COLUMN B ----------- OTHER ------------- ADDITIONS COLUMN D CHANGES -- COLUMN F COLUMN A BALANCE AT CHARGED TO ----------- ADD (DEDUCT) ------------- - ----------------------------------------------------- BEGINNING OF COSTS AND RETIREMENTS -- BALANCE AT DESCRIPTION PERIOD EXPENSES (DEDUCT) DESCRIBE END OF PERIOD - ----------------------------------------------------- ------------- ----------- ----------- -------------- ------------- (IN THOUSANDS) Accumulated Provision for Depreciation of Utility Plant: Electric........................................... $ 1,434,259 $ 154,962 $ (31,599) $ 21,668(A) $ 1,579,290 Gas................................................ 180,050 16,049 (44,663) (3,434)(B) 148,002 Common............................................. 69,193 18,838 (9,393) 703(B) 79,341 ------------- ----------- ----------- -------------- ------------- Total............................................ 1,683,502 189,849 (85,655) 18,937 1,806,633 ------------- ----------- ----------- -------------- ------------- Accumulated Provision for Amortization of Utility Plant............................................... 10,664 7,893 -- (2,810)(C) 15,747 ------------- ----------- ----------- -------------- ------------- Total Accumulated Provision for Depreciation and Amortization of Utility Plant....................... $ 1,694,166 $ 197,742 $ (85,655) $ (16,127) $ 1,822,380 ------------- ----------- ----------- -------------- ------------- ------------- ----------- ----------- -------------- ------------- Accumulated Provision for Amortization of Nuclear Fuel Assemblies..................................... $ 616,709 ------------- ------------- Accumulated Provision for Amortization of Other Physical Property................................... $ 1,891 ------------- ------------- Accumulated Provision for Amortization and Depreciation of Property of: Constellation Holdings, Inc........................ $ 19,889 ------------- ------------- BNG, Inc........................................... $ 4,274 ------------- ------------- - -------------------------- (A) Represents principally AFC resulting from the adoption by the Company of Statement of Financial Accounting Standards No. 109. (B) Represents principally net cost of removal and salvage applicable to retired property. (C) Represents principally write-off of utility plant which is fully amortized.
NOTE: For a statement of the Company's depreciation policy, see NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS. The Company's Accumulated Provision for Depreciation is not segregated according to the "Classification" of property shown under "Plant in Service" in Schedule V. 63 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VII -- GUARANTEES OF SECURITIES OF OTHER ISSUERS AS OF DECEMBER 31, 1993
COLUMN G -------------------- NATURE OF ANY COLUMN E DEFAULT BY ISSUER OF COLUMN B COLUMN D ---------- SECURITIES COLUMN A ------------- --------------- AMOUNT IN GUARANTEED IN - ------------------------ TITLE OF COLUMN C AMOUNT OWNED BY TREASURY PRINCIPAL, INTEREST, NAME OF ISSUER OF ISSUE OF EACH --------------- PERSON OR OF ISSUER COLUMN F SINKING FUND OR SECURITIES CLASS OF TOTAL AMOUNT PERSONS FOR OF ------------- REDEMPTION GUARANTEED BY PERSON FOR SECURITIES GUARANTEED AND WHICH STATEMENT SECURITIES NATURE OF PROVISIONS, OR WHICH STATEMENT IS FILED GUARANTEED OUTSTANDING IS FILED GUARANTEED GUARANTEE PAYMENT OF DIVIDENDS - ------------------------ ------------- --------------- --------------- ---------- ------------- -------------------- (IN THOUSANDS) BGE: Safe Harbor Water Power Corporation............ Serial Notes $ 26,667(A) -- -- Principal and -- interest (C) CONSTELLATION COMPANIES: Puna.................... Note(s) (B) 15,000 -- -- Principal and Default (D) interest (C) Aspenwood L.P........... Note(s) (B) 9,953 -- -- Principal and -- interest (C) Piney Orchard L.P....... Note(s) (B) 6,909 -- -- Principal and -- interest (C) Pacific-Ultrapower Chinese Station........ Note(s) (B) 5,637 -- -- Principal and -- interest (C) Sunrise Falls Church.... Note(s) (B) 4,950 -- -- Principal and -- interest (C) Jolly Acres L.P......... Note(s) (B) 2,593 -- -- Principal and -- interest (C) Mammoth Lakes........... Note(s) (B) 1,765 -- -- Principal and -- interest (C) Ace Cogeneration Company................ Note(s) (B) 1,750 -- -- Principal and -- interest (C) Troutman................ Note(s) (B) 840 -- -- Principal and -- interest (C) Constellation Real Estate, Inc............ Note(s) (B) 355 -- -- Principal and -- interest (C) Hickory Ridge........... Note(s) (B) 186 -- -- Principal and -- interest (C) Panther Creek........... Note(s) (E) 37 -- -- Rent (E) -- --------------- $ 76,642 --------------- --------------- - ---------------------------------- (A) BGE has agreed to guarantee 66 2/3% of up to $125 million of indebtedness incurred by Safe Harbor Water Power Corporation in connection with the 1985-1986 expansion of its hydroelectric generating facilities. Such borrowings are to mature in various years through 2001. The outstanding loans totaled $40,000,000 and $45,000,000 as of December 31, 1993 and 1992, respectively, of which $26,666,667 and $30,000,000, respectively, was guaranteed by BGE. Also, as of December 31, 1993, interest payable on the loans totaled $779,167 of which $519,445 is guaranteed by BGE. (B) Wholly owned subsidiaries of Constellation Holdings, Inc. have guaranteed loans for power facilities and real estate projects. (C) No material amount of interest was outstanding during the period as substantially all interest is due and has been paid monthly, quarterly, or semi-annually on the related notes. (D) As of December 31, 1993, the Puna debt is in technical default due to a delay in converting the construction debt to permanent financing. No formal default notice has been issued concerning these delays. None of the Constellation Companies was the borrower under the Puna debt that was in default, and none of the Constellation Companies defaulted on its guaranty obligations relating to such debt. (E) A wholly owned subsidiary of Constellation Holdings, Inc. has made a rent guarantee for an energy project.
64 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
COLUMN C COLUMN B ------------------------------ -------- BALANCE ADDITIONS COLUMN E AT ------------------------------ COLUMN D ---------- COLUMN A BEGINNING CHARGED TO CHARGED TO OTHER ---------------- BALANCE AT - ----------------------------------------------------- OF COSTS AND ACCOUNTS -- (DEDUCTIONS) -- END OF DESCRIPTION PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD - ----------------------------------------------------- -------- ------------ ---------------- ---------------- ---------- (IN THOUSANDS) Reserves deducted in the Balance Sheet from the assets to which they apply: Accumulated Provision for Uncollectibles 1993............................................. $ 12,484 $ 19,155 $ -- $ (17,682)(A) $ 13,957 1992............................................. 11,911 18,910 -- (18,337)(A) 12,484 1991............................................. 10,708 15,095 -- (13,892)(A) 11,911 Valuation Allowance -- Net unrealized loss on marketable securities 1993............................................. -- -- -- -- -- 1992............................................. -- -- -- -- -- 1991............................................. 13,988 -- -- (13,988)(B) -- Provision for possible disallowance of replacement energy costs 1993............................................. 35,000 -- -- -- 35,000 1992............................................. 35,000 -- -- -- 35,000 1991............................................. 35,000 -- -- -- 35,000 Loan loss reserve 1993............................................. 4,382 741 -- -- 5,123 1992............................................. 3,856 526 -- -- 4,382 1991............................................. -- 3,856 -- -- 3,856 Energy project reserves 1993............................................. 492 1,286 -- -- 1,778 1992............................................. 494 -- -- (2)(C) 492 1991............................................. 63 555 -- (124)(C) 494 - -------------------------- (A) Represents principally net amounts charged off as uncollectible. (B) Represents change in common shareholders' equity to reflect reversal of previous temporary decline in market value of subsidiary's noncurrent investment securities. (C) Represents recovery of subsidiary's project development costs previously reversed as uncollectible.
65 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized. BALTIMORE GAS AND ELECTRIC COMPANY (Registrant) Date: March 18, 1994 By /s/ C. H. POINDEXTER ------------------------------------------------- C. H. Poindexter CHAIRMAN OF THE BOARD
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE - ------------------------------------------------------------------------------------ ---------------------- ------------------- Principal executive officer and director: By /s/ C. H. POINDEXTER -------------------------------------------------------------------------------- Chairman of the Board March 18, 1994 C. H. Poindexter and Director Principal financial and accounting officer: By /s/ C. W. SHIVERY -------------------------------------------------------------------------------- Vice President and March 18, 1994 C. W. Shivery Secretary Directors: /s/ H. F. BALDWIN - ----------------------------------------------------------------------------------- Director March 18, 1994 H. F. Baldwin /s/ B. B. BYRON - ----------------------------------------------------------------------------------- Director March 18, 1994 B. B. Byron /s/ J. O. COLE - ----------------------------------------------------------------------------------- Director March 18, 1994 J. O. Cole /s/ D. A. COLUSSY - ----------------------------------------------------------------------------------- Director March 18, 1994 D. A. Colussy /s/ E. A. CROOKE - ----------------------------------------------------------------------------------- Director March 18, 1994 E. A. Crooke /s/ J. R. CURTISS - ----------------------------------------------------------------------------------- Director March 18, 1994 J. R. Curtiss /s/ J. W. GECKLE - ----------------------------------------------------------------------------------- Director March 18, 1994 J. W. Geckle /s/ F. A. HRABOWSKI III - ----------------------------------------------------------------------------------- Director March 18, 1994 F. A. Hrabowski III /s/ N. LAMPTON - ----------------------------------------------------------------------------------- Director March 18, 1994 N. Lampton /s/ G. V. MCGOWAN - ----------------------------------------------------------------------------------- Director March 18, 1994 G. V. McGowan /s/ P. G. MILLER - ----------------------------------------------------------------------------------- Director March 18, 1994 P. G. Miller /s/ G. L. RUSSELL, JR. - ----------------------------------------------------------------------------------- Director March 18, 1994 G. L. Russell, Jr. /s/ M. D. SULLIVAN - ----------------------------------------------------------------------------------- Director March 18, 1994 M. D. Sullivan
66 EXHIBIT INDEX
EXHIBIT PAGE NUMBER NUMBER - ------------ --------- *3(a) -- *3(b) -- 4(a) 70 -- EXHIBIT NUMBER - ------------ *3(a) Charter of BGE, restated as of October 13, 1993. (Designated as Exhibit No. 3(b) in Form 10-Q dated November 12, 1993, File No. 1-1910.) *3(b) By-Laws of BGE, as amended to March 1, 1993. (Designated as Exhibit No. 3(c) in Form 10-K Annual Report for 1992, File No. 1-1910.) 4(a) Indenture and Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN ---------------------------------------------------------------------------------- EXHIBIT DATED FILE NO. NUMBER ------------------------- ----------- -------------- *February 1, 1919 2-2640 B-3 *December 1, 1920 2-2640 B-4 *October 1, 1921 2-2640 B-5 *September 1, 1922 2-2640 B-6 *June 1, 1925 2-2640 B-7 *March 1, 1929 2-2640 B-8 *July 1, 1930 2-2640 B-9 *June 1, 1931 2-2640 B-10 *November 1, 1934 2-2640 B-11 *May 1, 1935 2-2640 B-12 *July 1, 1935 2-2640 B-13 *December 1, 1936 2-3708 B-14 *June 15, 1938 1-1910-2 (Form 8-K Report for June 1938) 1 *June 1, 1939 2-4625 B-15 *January 1, 1941 2-6296 B-16 *April 1, 1946 2-7020 7-17 *March 1, 1948 1-1910-2 (Form 8-K Report for March 1948) 1 *December 19, 1949 2-8740 7-19 *December 20, 1949 2-8740 7-20 *June 15, 1950 2-8740 7-21 *January 15, 1951 2-9916 4-30 *June 1, 1953 2-9916 4-33 *July 15, 1954 2-11676 4-3 *December 1, 1955 2-13127 4-3 *March 1, 1958 1-1910-P (Form 8-A dated March 12, 1958) 1-2 *June 1, 1960 1-1910 (Form 8-K for June 1960) 1 *July 15, 1962 1-1910 (Form 8-K for July 1962) 1 *July 15, 1964 2-23763 2-3 *July 26, 1965 2-24800 2-3 *April 15, 1966 2-26278 4-3 *June 16, 1967 2-27005 2-3 *August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1 *December 15, 1968 1-1910 (Form 10-K Annual Report for 1968) D-1 *September 15, 1969 2-35453 2-6 *April 1, 1970 1-1910 (Form 8-A dated March 30, 1970) 2(b) *July 1, 1970 1-1910 (Form 8-A dated June 30, 1970) 2(c) *September 15, 1970 2-39561 2-4 *April 15, 1971 2-41252 2-4 *September 1, 1971 2-42574 2-4 *January 1, 1972 1-1910 (Form 10-K Annual Report for 1971) A-2 *July 1, 1972 2-45452 2-3 *September 15, 1972 1-1910 (Form 10-K Annual Report for 1972) A-1 *August 15, 1973 1-1910 (Form 8-K Report for August 1973) 3-4
67
DESIGNATED IN ---------------------------------------------------------------------------------- EXHIBIT DATED FILE NO. NUMBER ------------------------- ----------- -------------- *February 1, 1974 1-1910 (Form 10-K Annual Report for 1973) A-1 *July 1, 1974 1-1910 (Form 8-A dated July 5, 1974) 2(b) *September 15, 1974 1-1910 (Form 8-A dated September 13, 1974) 2(b) *August 1, 1975 1-1910 (Form 8-A dated August 5, 1975) 2(b) *September 15, 1976 1-1910 (Form 8-A dated September 24, 1976) 2(b) *July 15, 1977 2-59772 2-3 (3 Indentures) *September 15, 1977 1-1910 (Form 8-A dated September 23, 1977) 2(c) *July 1, 1978 1-1910 (Form 8-A dated June 30, 1978) 2(b) *September 15, 1979 1-1910 (Form 10-Q dated November 14, 1979) 2-5 and 2-6 (2 Indentures) *September 15, 1980 1-1910 (Form 8-A dated September 12, 1980) 2(b) *July 8, 1981 1-1910 (Form 10-Q dated August 17, 1981) 20-2(c) *October 1, 1981 1-1910 (Form 8-A dated September 29, 1981) 2(b) *July 15, 1982 1-1910 (Form 8-A dated July 28, 1982) 2(b) *March 1, 1986 1-1910 (Form 8-A dated February 24, 1986, as amended by Form 2 8 dated March 3, 1986) *June 15, 1987 1-1910 (Form 8-K Report for July 29, 1987) 4(a) *October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a) *October 15, 1990 33-38803 (Form S-3 Registration) 4(a) *August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i) *January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii) *July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a) *February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i) *March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii) *March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii) *April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4 *July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a) *July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b) *October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4 70 March 15, 1994 (Filed Herewith) 4(a)
*4(b) -- Indenture dated July 1, 1985, between BGE and Mercantile-Safe Deposit and Trust Company, Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).) *10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan. (Designated as Exhibit No. 10(a) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) 10(b) 78 -- Summary of amendment to the Baltimore Gas and Electric Company Executive Benefits Plan. *10(c) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) *10(d) -- Baltimore Gas and Electric Company Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) *10(e) -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Executive Officers. (Designated as Exhibit No. 10(d) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.)
68
EXHIBIT PAGE NUMBER NUMBER - ----------- --------- 10(f) 79 -- Baltimore Gas and Electric Company Non-qualified Deferred Compensation Plan for Non- Employee Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for Non-Employee Directors). 10(g) 82 -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. 10(h) 83 -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. *10(i) -- Constellation Holdings, Inc., Summary of Executive Benefits Plan. (Designated as Exhibit No. 10(f) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) *10(j) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) in the Form 10-K Annual Report for the year ended December 31, 1992, File No. 1-1910.) 10(k) 84 -- Amended Summary 1992 Long Term Incentive Plan of Constellation Holdings, Inc. 12 85 -- Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. 21 86 -- Subsidiaries of the Registrant. 23 87 -- Consent of Coopers & Lybrand, Independent Auditors (see page 73 in this Form 10-K). *99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.) *99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland. (Designated as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31, 1987, File No. 1-1910.) - -------------------------- *Incorporated by Reference.
69 EX-4 2 EXHIBIT 4(A) EXHIBIT 4(A) - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- BALTIMORE GAS AND ELECTRIC COMPANY TO BANKERS TRUST COMPANY, TRUSTEE ---------------- SUPPLEMENTAL INDENTURE SUPPLEMENTING DEED OF TRUST DATED FEBRUARY 1, 1919 --------------------- TO SECURE $125,000,000 FLOATING RATE SERIES DUE APRIL 15, 1999 FIRST REFUNDING MORTGAGE BONDS - -------------------------------------------------------------------------------- - -------------------------------------------------------------------------------- 70 SUPPLEMENTAL INDENTURE, made as of the fifteenth day of March in the year nineteen hundred and ninety-four, for convenience of reference, and effective from the time of execution and delivery hereof, by and between BALTIMORE GAS AND ELECTRIC COMPANY (name changed from CONSOLIDATED GAS ELECTRIC LIGHT AND POWER COMPANY OF BALTIMORE on April 4, 1955), a corporation duly created and organized under the law of the State of Maryland, hereinafter called the "Company," party of the first part, and BANKERS TRUST COMPANY, a corporation duly created and organized under the law of the State of New York, having its principal office and place of business at Four Albany Street, Borough of Manhattan, The City of New York, hereinafter called the "Trustee," party of the second part. WHEREAS, The Company heretofore duly executed, acknowledged and delivered to the Trustee (a) an indenture of mortgage or deed of trust dated February 1, 1919 (which as amended and/or supplemented by the seventy-two supplemental indentures hereinafter mentioned, is hereinafter called the "Refunding Mortgage"), recorded among the Land Records or Mortgage Records (as the case may be) of Baltimore City, Baltimore County, Howard County, Anne Arundel County, Carroll County, Harford County, Montgomery County, Prince George's County, Calvert County, Cecil County, and Frederick County, Maryland, and indexed among the Chattel Records of Baltimore City and each of the counties aforesaid except Frederick County; (b) twenty-six successive indentures supplemental to and forming a part of the Refunding Mortgage, dated respectively as of December 1, 1920, October 1, 1921, September 1, 1922, June 1, 1925, March 1, 1929, July 1, 1930, June 1, 1931, November 1, 1934, May 1, 1935, July 1, 1935, December 1, 1936, June 15, 1938, June 1, 1939, January 1, 1941, April 1, 1946, March 1, 1948, December 19, 1949, December 20, 1949, June 15, 1950, January 15, 1951, June 1, 1953, July 15, 1954, December 1, 1955, March 1, 1958, June 1, 1960, and July 15, 1962, each recorded among the Land Records or Mortgage Records (as the case may be) of Baltimore City and the counties aforesaid, and recorded or indexed (as the case may be) among the Chattel Records of Baltimore City and the counties aforesaid except Frederick County; (c) forty-four indentures supplemental to and forming a part of the Refunding Mortgage, dated as of July 15, 1964, April 15, 1966, August 1, 1967, December 15, 1968, September 15, 1969, April 1, 1970, July 1, 1970, September 15, 1970, April 15, 1971, September 1, 1971, January 1, 1972, July 1, 1972, September 15, 1972, August 15, 1973, February 1, 1974, July 1, 1974, September 15, 1974, August 1, 1975, September 15, 1976, July 15, 1977 (three supplemental indentures), September 15, 1977, July 1, 1978, September 15, 1979 (two supplemental indentures), September 15, 1980, July 8, 1981, October 1, 1981, July 15, 1982, March 1, 1986, June 15, 1987, October 15, 1989, October 15, 1990, August 15, 1991, January 15, 1992, July 1, 1992, February 15, 1993, March 1, 1993, March 15, 1993, April 15, 1993, July 1, 1993, July 15, 1993, and October 15, 1993, and each recorded among the Land Records of Baltimore City and the counties aforesaid (with respect to personal property and fixtures located in Maryland now owned or hereafter acquired by the Company, the lien of the Refunding Mortgage has been perfected as a security interest under the Maryland Uniform Commercial Code, by recording and indexing a financing statement in the office of the Maryland State Department of Assessments and Taxation); (d) the aforesaid indenture of mortgage or deed of trust dated February 1, 1919, and the following indentures supplemental thereto dated as of December 1, 1920, November 1, 1934, December 1, 1936, June 15, 1938, January 1, 1941, April 1, 1946, December 19, 1949, December 20, 1949, June 15, 1950, January 15, 1951, July 15, 1954, December 1, 1955, March 1, 1958, June 1, 1960, July 15, 1962, July 15, 1964, April 15, 1966, August 1, 1967, December 15, 1968, September 15, 1969, April 1, 1970, July 1, 1970, September 15, 1970, April 15, 1971, September 1, 1971, January 1, 1972, July 1, 1972, September 15, 1972, August 15, 1973, February 1, 1974, July 1, 1974, September 15, 1974, August 1, 1975, September 15, 1976, July 15, 1977 (three supplemental indentures), September 15, 1977, July 1, 1978, September 15, 1979 (two supplemental indentures), September 15, 1980, July 8, 1981, October 1, 1981, July 15, 1982, March 1, 1986, June 15, 1987, October 15, 1989, October 15, 1990, August 15, 1991, January 15, 1992, July 1, 1992, February 15, 1993, March 1, 1993, March 15, 1993, April 15, 1993, July 1, 1993, July 15, 1993, and October 15, 1993, have been duly recorded in mortgage books in the respective offices of the Recorders of Deeds in and for Adams County, Armstrong County, Bedford County, Blair County, Cambria County, Cumberland County, Franklin County, Huntingdon County, Indiana County, Montgomery County, Westmoreland County, and York County, Pennsylvania; (e) and also Supplemental Indentures dated July 26, 1965 and June 16, 1967 have been duly recorded in mortgage books in the respective offices of the Recorders of Deeds in and for Armstrong and Indiana Counties, Pennsylvania; and (f) the aforesaid indenture of mortgage or deed of trust dated February 1, 1919 and the following supplemental indentures thereto dated as of December 1, 1920, November 1, 1934, December 1, 1936, June 15, 1938, January 1, 1941, April 1, 1946, December 19, 1949, March 1, 1958, July 15, 1964, April 15, 1966, August 1, 1967, December 15, 1968, April 1, 1970, April 15, 1971, September 1, 1971, January 1, 1972, July 1, 1972, September 15, 1972, August 15, 1973, February 1, 1974, September 15, 1976, July 15, 1977 (three supplemental indentures), September 15, 1977, July 1, 1978, September 15, 1979 (two supplemental indentures), March 1, 1986, June 15, 1987, October 15, 1989, October 15, 1990, August 15, 1991, January 15, 1992, July 1, 1992, February 15, 1993, March 1, 1993, March 15, 1993, April 15, 1993, July 1, 1993, July 15, 1993, and October 15, 1993, have been duly recorded in the mortgage books in the office of the Recorder of Deeds in and for Montgomery County, Pennsylvania (with respect to personal property and fixtures located in Pennsylvania, now owned or hereafter acquired by the Company, the 71 lien of the Refunding Mortgage has been perfected as a security interest under the Pennsylvania Uniform Commercial Code by filing a financing statement in the office of the Secretary of the Commonwealth of the Commonwealth of Pennsylvania); which Refunding Mortgage is hereby referred to and made a part hereof as fully as if herein recited at length, and the several corporations, mortgages or deeds of trust, indentures, bonds, notes, securities and stocks referred to in the Refunding Mortgage are, when hereinafter referred to, sometimes referred to by the short names by which they are referred to in the Refunding Mortgage, and the several words, terms and expressions particularly defined or construed in the Refunding Mortgage, in Section 4 or Section 5 of Article XI thereof or elsewhere, when used in this supplemental indenture are used as so defined or construed in the Refunding Mortgage; and WHEREAS, By the Refunding Mortgage it is among other things provided, in Section 9 of Article III thereof, that from time to time the Company, when authorized by a resolution of its Board of Directors, and the Trustee may, subject to the provisions of the Refunding Mortgage, execute, acknowledge and deliver indentures supplemental thereto, which thereafter shall form a part thereof, for the purpose (among others) of conveying, assuring or confirming to, or vesting in, the Trustee additional property now owned or hereafter acquired pursuant to Section 7 of Article I or Section 2 of Article III of the Refunding Mortgage, adding to the covenants of the Company in the Refunding Mortgage for the protection of the holders of the Securities, making provisions for the redemption before maturity of any bonds thereafter to be issued thereunder, or making such provision, not inconsistent with the Refunding Mortgage, as may be necessary or desirable with respect to matters or questions arising thereunder; and WHEREAS, The Company has determined to issue additional bonds under and pursuant to the provisions of the Refunding Mortgage and has determined to execute, acknowledge and deliver this indenture, supplemental to the Refunding Mortgage and hereafter to form a part thereof, for the purpose of conveying, assuring or confirming to, or vesting in, the Trustee additional property now owned or hereafter acquired pursuant to Section 7 of Article I or Section 2 of Article III of the Refunding Mortgage, adding to the covenants of the Company in the Refunding Mortgage for the protection of the holders of the Securities, making provisions for the redemption before maturity of bonds hereafter to be issued under the Refunding Mortgage, and making such provision, not inconsistent with the Refunding Mortgage, as may be necessary or desirable with respect to matters or questions arising thereunder, and the Company and the Trustee are willing so to execute, acknowledge and deliver this supplemental indenture for the purposes aforesaid; and WHEREAS, At meetings of the Board of Directors of the Company duly called and held as provided by law on the seventeenth day of September, 1993 and the eighteenth day of February, 1994, at which meetings a quorum of said Board of Directors was present and voted, this supplemental indenture was then and there submitted to the said Board of Directors and resolutions authorizing the execution, acknowledgment and delivery of this supplemental indenture and the issuance, certification and delivery of First Refunding Mortgage Bonds under and pursuant to the provisions of the Refunding Mortgage, as so supplemented by this supplemental indenture, were unanimously adopted by the affirmative vote of all the members so present. NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE WITNESSETH: That, in order to secure the payment of the principal of and interest on all such bonds at any time issued and outstanding under the Refunding Mortgage, according to their tenor and effect, and to secure the performance of all the covenants and conditions contained in the Refunding Mortgage as supplemented by this supplemental indenture, and to declare the terms and conditions upon which said bonds are issued, or to be issued, and secured under the Refunding Mortgage, Baltimore Gas and Electric Company, the party of the first part, in consideration of the premises and of the purchase of such bonds by the holders thereof, and of the sum of one dollar, lawful money of the United States of America, to it duly paid by the Trustee at or before the ensealing and delivery of these presents, the receipt whereof is hereby acknowledged, has executed and delivered these presents and hereby ratifies, approves and confirms the Refunding Mortgage in all respects as fully as if all the terms, provisions, covenants and conditions thereof were herein again set forth at length, as supplemented hereby, and has granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged, pledged, set over and confirmed, and granted a security interest therein, and by these presents does grant, bargain, sell, release, convey, assign, transfer, mortgage, pledge, set over and confirm, and grant a security interest therein unto Bankers Trust Company, party of the second part, and unto its successors and assigns forever, all and singular the premises, property and franchises of the Company other than as excepted in the Refunding Mortgage, now owned or hereafter acquired in Maryland or Pennsylvania. TOGETHER with all the rights, privileges and appurtenances to any of said premises, property and franchises belonging or in anywise appertaining, and the reversion and reversions, remainder and remainders, rents, issues, income and profits thereof, and all the estate, right, title and interest which the Company now has or may hereafter acquire therein or thereto or in or to any part thereof. 72 TO HAVE AND TO HOLD, All and singular the said premises, property and franchises, appurtenances, rents, issues, income and profits hereby conveyed, transferred, assigned and confirmed, or intended so to be, unto the Trustee, its successors and assigns, forever. IN TRUST, NEVERTHELESS, For the equal and proportionate benefit and security of all holders of the bonds and interest obligations issued or to be issued under the Refunding Mortgage, and for the enforcement of the payment of said bonds and interest obligations when payable and the performance of and compliance with the covenants and conditions of the Refunding Mortgage as supplemented by this supplemental indenture, without preference, priority or distinction, as to lien or otherwise of any series of bonds over any other series of bonds, or of any one bond over any other bonds, by reason of priority in the issue or negotiation thereof or otherwise, so that each and every bond issued or to be issued under the Refunding Mortgage or secured thereby shall have the same right, lien and privilege under the Refunding Mortgage as supplemented by this supplemental indenture, and so that the principal and interest of every such bond, subject to the terms of the Refunding Mortgage as so supplemented, be equally and proportionately secured thereby as if all had been duly made, executed, delivered, sold and negotiated simultaneously with the execution and delivery of the Refunding Mortgage, it being intended that the lien and security of the Refunding Mortgage shall take effect from the date of the execution and delivery thereof without regard to the time of such actual issue, sale or disposition of said bonds, and as though upon said date all of said bonds had been actually issued, sold and delivered to, and were in the hands of, holders thereof for value. AND IT IS HEREBY FURTHER COVENANTED AND DECLARED, That all such bonds are issued and certified and delivered, or to be issued and certified and delivered, and the mortgaged premises and property are to be held by the Trustee, subject to the further covenants, conditions, uses and trusts in the Refunding Mortgage, as supplemented by this supplemental indenture, set forth, and it is agreed and covenanted by the Company with the Trustee and the respective holders from time to time of bonds issued under the Refunding Mortgage as follows, viz: 1. As supplemented hereby, each and all of the terms, provisions, covenants, conditions, uses and trusts set forth in that portion of the Refunding Mortgage beginning with and including the words "Article I. Issue and Appropriation of Bonds," and continuing to the end of the Refunding Mortgage, as supplemented and amended by the seventy-two successive supplemental indentures herein above mentioned, are hereby expressly ratified, approved and confirmed, as fully and with the same force and effect as if the same were herein again set forth at length, provided, however, that no provision of this Supplemental Indenture is intended to reinstate any provisions in the Refunding Mortgage which were amended and superseded by the amendments to the Trust Indenture Act of 1939 effective as of November 15, 1990. 2. One series of bonds to be issued under and secured by the Refunding Mortgage shall be designated as Floating Rate Series due April 15, 1999, First Refunding Mortgage Bonds (hereinafter called "bonds of the Designated Series"). Bonds of the Designated Series shall be issued only as registered bonds in denominations of one thousand dollars and multiples thereof. Bonds of the Designated Series may be exchanged for a like aggregate principal amount of bonds of the Designated Series of other denominations. Each bond of the Designated Series shall be dated the date of its authentication, shall mature April 15, 1999, shall be payable as to principal and interest in lawful money of the United States of America which shall be legal tender at the time such payment becomes due, at the principal office of Bankers Trust Company (or its successor in trust), in the Borough of Manhattan, in The City of New York, or at such other institutions as designated by the Company, provided, however, that each installment of interest may be paid by mailing checks, or by wire transfers, for such interest payable to the order of the person entitled thereto to the registered address of such person as it appears on the books of the Company, and shall bear interest from the fifteenth day of January, April, July or October, as the case may be, to which interest has been paid on the bonds of the Designated Series (unless the date of such bond is prior to July 15, 1994, in which case it shall bear interest from March 21, 1994), provided however, that, subject to the provisions of this Section with respect to failure by the Company to pay any interest on an interest payment date, the holder of any bond dated after a record date (as hereinafter defined) for the payment of interest and prior to the date of payment of such interest shall not be entitled to payment of such interest and shall have no claim against the Company with respect thereto. Bonds of the Designated Series shall bear interest at the three month London interbank offered rate ("LIBOR") plus .15 per cent per annum as calculated and reset in the manner and at the times as described below in Section 3, payable quarterly on the fifteenth days of January, April, July and October in each year (the "Interest Payment Dates"). The first interest payment shall be made on July 15, 1994. The interest payable on any interest payment date shall be paid to the persons in whose names bonds of the Designated Series were registered at the close of business on the record date for such payment of interest notwithstanding any cancellation of bonds of the Designated Series on any transfer or exchange thereof between such record date and such interest payment date; except that if the Company shall default in the payment of any interest due on such interest payment date such defaulted interest shall be paid to the persons in whose names bonds of the Designated Series are registered either at the close of business on the subsequent 73 record date fixed for payment of such defaulted interest, or (if no such subsequent record date shall have been fixed) at the close of business on the day preceding the date of payment of such defaulted interest. A subsequent record date for payment of defaulted interest may be established by or on behalf of the Company by notice to holders of bonds of the Designated Series not less than ten days preceding such record date, which record date shall be not more than thirty days prior to the subsequent interest payment date. The term "record date" as used herein shall mean, with respect to any regular interest payment date, the close of business on the last day of the calendar month next preceding such interest payment date. The bonds may also be represented by a permanent global bond or bonds, registered in the name of The Depository Trust Company, as depositary (the "Depositary"), or a nominee of the Depositary (each such bond represented by a permanent global bond being referred to herein as a "Book-Entry Bond"). Beneficial interests in Book-Entry Bonds will only be evidenced by, and transfers thereof will only be effected through, records maintained by the Depositary's participants. The Company shall not be required to make transfers or exchanges of bonds of the Designated Series during a period of fifteen days preceding the mailing of notice of a partial redemption of bonds of such Series, or to transfer or exchange bonds of the Designated Series, or the portion thereof, which shall have been designated for redemption. Upon thirty days' notice in the manner set forth in Article X, Section 2 of the Refunding Mortgage, bonds of the Designated Series at any time outstanding shall be redeemable prior to maturity, as a whole at any time, or in part from time to time, at the option of the Company, at 100% of principal amount, if redeemed otherwise than by operation of the sinking fund, and, at any time after July 31, 1996, by operation of the sinking fund provided for by Article X, Section 3 of the Refunding Mortgage, at 100% of principal amount, with accrued interest to the date of redemption, provided, however, that prior to April 15, 1996, none of the bonds of the Designated Series may be redeemed. 3. Bonds of the Designated Series will bear interest at the interest rate calculated based upon three month LIBOR plus .15%. LIBOR will be determined on the second London Business Day (as defined below) prior to the first day of each Interest Period (the "Interest Determination Date"). The period commencing on an Interest Payment Date and ending on and excluding the next succeeding Interest Payment Date is called an "Interest Period," with the exception that the first Interest Period shall extend from March 21, 1994 to July 15, 1994, the first Interest Payment Date. LIBOR will be determined by Bankers Trust Company acting as calculation agent (the "Calculation Agent") in accordance with the following provisions: (a) With respect to any Interest Determination Date, LIBOR will be determined on the basis of the offered rates for deposits of not less than $1,000,000 having the index maturity of three months, commencing on the second business day on which dealings in deposits in U.S. dollars are transacted in the London interbank market ("London Business Day") immediately following such Interest Determination Date, which appear on the Reuters Screen LIBO Page as of 11:00 A.M., London time, on that Interest Determination Date. If at least two such offered rates appear on the Reuters Screen LIBO Page, the rate for such Interest Determination Date will be the arithmetic mean of such offered rates as determined by the Calculation Agent. (b) With respect to an Interest Determination Date on which fewer than two offered rates for the three month index maturity appear on the Reuters Screen LIBO Page as described in (a) above, LIBOR will be determined on the basis of the rates at approximately 11:00 A.M., London time, on such Interest Determination Date at which deposits in U.S. dollars having the three month index maturity are offered to prime banks in the London interbank market by four major banks in the London interbank market selected by the Calculation Agent commencing on the second London Business Day immediately following such Interest Determination Date and in a principal amount not less than $1,000,000 that in the Calculation Agent's judgment is representative for a single transaction in such market at such time (a "Representative Amount"). The Calculation Agent will request the principal London office of each of such banks to provide a quotation of its rate. If at least two such quotations are provided, LIBOR for such Interest Determination Date will be the arithmetic mean of such quotations. If fewer than two quotations are provided, LIBOR for such Interest Determination Date will be the arithmetic mean of the rates quoted at approximately 11:00 A.M., New York City time, on such Interest Determination Date by three major banks in The City of New York, selected by the Calculation Agent, for loans in U.S. dollars to leading European banks having the three month index maturity commencing on the second London Business Day immediately following such Interest Determination Date and in a Representative Amount; PROVIDED, HOWEVER, that if fewer than three banks selected as aforesaid by the Calculation Agent are quoting as mentioned in this sentence, the rate of interest in effect for the applicable period will be the same as the rate of interest in effect for the immediately preceding Interest Period. 4. The recitals of fact contained herein, in the Refunding Mortgage as hereby supplemented, and in the bonds (other than the certificate of authentication of the Trustee on the bonds), shall be taken as the statements of the Company, and the Trustee assumes no responsibility for the correctness of the same. The Trustee makes no representations to the value of the mortgaged property or any part thereof, or as to the title of the Company thereto, or as to the value or validity of the security afforded thereby and by the Refunding Mortgage, or as to the 74 value or validity of any securities at any time held under the Refunding Mortgage, or as to the validity of this supplemental indenture or the Refunding Mortgage or of the bonds issued thereunder, and the Trustee shall incur no responsibility, except as otherwise provided in the Refunding Mortgage, in respect of such matters. 5. If and to the extent that any provision of this supplemental indenture limits, qualifies, or conflicts with another provision of the Refunding Mortgage required to be included therein by any of Sections 310 to 317, inclusive, of the Trust Indenture Act of 1939, as amended, such required provision shall control; provided, however that nothing in this supplemental indenture contained shall be so construed as to relieve the Company or the Trustee of any duty or obligation which it would otherwise have to any holder of any bond or bonds heretofore issued under the Refunding Mortgage, or so construed as to grant to the Trustee any rights as against any holder of bond or bonds heretofore issued under the Refunding Mortgage not granted under said Refunding Mortgage, and no provision in this supplemental indenture contained shall impair any of the rights of any holder of any bond or bonds heretofore issued under the Refunding Mortgage. 6. All the provisions of this supplemental indenture shall become effective immediately. This supplemental indenture and all the provisions thereof shall form a part of the Refunding Mortgage and all references or mention in the Refunding Mortgage to the Refunding Mortgage or to any of the terms, provisions, covenants, conditions, uses or trusts thereof or the recitals or statements therein or to the recording, filing or refiling thereof, shall be applicable to the terms, provisions, covenants, conditions, uses and trusts of, and the recitals and statements in, this supplemental indenture and the Refunding Mortgage as hereby supplemented, and to the recording, filing and refiling thereof, as fully and with the same force and effect as if all the terms, provisions, covenants, conditions, uses and trusts of, and all the recitals and statements in, the Refunding Mortgage were herein again set forth at length and the entire Refunding Mortgage as hereby supplemented were herein set forth at length as one new instrument. IN TESTIMONY WHEREOF, on this fourteenth day of March, 1994, Baltimore Gas and Electric Company has caused these presents to be signed in its corporate name by its President or a Vice President, and its corporate seal to be hereunto affixed, duly attested by its Secretary or an Assistant Secretary; and Bankers Trust Company has also caused these presents to be signed in its corporate name by its President or a Vice President or an Assistant Vice President, and its corporate seal to be hereunto affixed, duly attested by one of its Assistant Secretaries. BALTIMORE GAS AND ELECTRIC COMPANY, By __________/s/_C.W. SHIVERY_________ Vice President Attest _______/s/_L.H. CHURCH______ (Seal) Assistant Secretary STATE OF MARYLAND: SS: CITY OF BALTIMORE:
I HEREBY CERTIFY, that on this fourteenth day of March, 1994, before me, the subscriber, a Notary Public of the State of Maryland, in and for the City of Baltimore aforesaid, personally appeared C.W. Shivery, Vice President of Baltimore Gas and Electric Company, and on behalf of the said corporation did acknowledge the foregoing instrument to be the act and deed of Baltimore Gas and Electric Company. IN TESTIMONY WHEREOF, I have hereunto set my hand and Notarial Seal on the day and year aforesaid. ___________/s/_GWEN SMETANA___________ Notary Public My Commission expires 11/17/97 [BANKERS TRUST COMPANY signature on next page] 75 BANKERS TRUST COMPANY, By ________/s/_ROBERT CAPORALE________ Vice President Attest ______/s/_SHIKHA DOMBEK_____ (Seal) Assistant Secretary STATE OF NEW YORK: SS: COUNTY OF NEW YORK:
I HEREBY CERTIFY, that on this 14th day of March, 1994, before me, the subscriber, a Notary Public of the State of New York, in and for the County of New York aforesaid, personally appeared Robert Caporale, Vice President of Bankers Trust Company, and on behalf of the said corporation did acknowledge the foregoing instrument to be the act and deed of Bankers Trust Company; and at the same time such Vice President, for and on behalf of said corporation, made oath in due form of law that the consideration stated in the foregoing deed of trust is true and bona fide as therein set forth, and also that he/she is a Vice President and agent of the said Bankers Trust Company, Trustee, grantee in the foregoing instrument and duly authorized to make this affidavit. IN TESTIMONY WHEREOF, I have hereunto set my hand and Notarial Seal on the day and year aforesaid. ____________/s/_JOHN FLORIO___________ Notary Public My Commission expires 12/20/95 76 CERTIFICATE OF RESIDENCE Bankers Trust Company, Mortgagee and Trustee within named, hereby certifies that its precise residence is Four Albany Street, in the Borough of Manhattan, in The City of New York, in the State of New York. BANKERS TRUST COMPANY, By ________/s/_ROBERT CAPORALE________ Vice President 77 EX-10 3 EXHIBIT 10(B) EXHIBIT 10(B) SUMMARY OF AMENDMENT TO THE BALTIMORE GAS AND ELECTRIC COMPANY EXECUTIVE BENEFITS PLAN During 1993, the Board of Directors of Baltimore Gas and Electric Company granted management the authority to amend the Executive Benefits Plan ("Plan") to secure the supplemental pension benefits of Plan participants. The amendment will not increase the amount of supplemental pension benefits under the Plan. In the past, the supplemental pension benefits were unfunded (i.e., no money was set aside on behalf of the executive as the benefit was earned), and the benefits were paid from the Company's general funds when the executive retired. To provide security, supplemental pension benefits under the Plan will now be accrued and funded through a trust at the time they are earned. An executive officer's accrued benefits in the trust become vested when any of these events occur: retirement eligibility; termination, demotion or loss of benefit eligibility without cause; a change of control of the Company followed within two years by the executive's demotion, termination or loss of benefit eligibility; or reduction of previously accrued benefits. As a result of becoming vested, the executive would be entitled to a payout of the vested amount from the trust upon the later of age 55 or employment termination. Payout of supplemental pension benefits will be available in the form of a lump sum payment. To date, no payments have been made to the trust. 78 EX-10 4 EXHIBIT 10(F) EXHIBIT 10(F) BALTIMORE GAS AND ELECTRIC COMPANY NON-QUALIFIED DEFERRED COMPENSATION PLAN FOR NON-EMPLOYEE DIRECTORS (PLAN) 1. OBJECTIVE. The objective of this Plan is to enable non-employee Directors of BGE to defer receipt of Compensation. 2. DEFINITIONS. All words beginning with an initial capital letter and not otherwise defined herein shall have the meaning set forth in the Employee Savings Plan. All singular terms defined in this Plan will include the plural and VICE VERSA. As used herein the following terms will have the meaning specified below: "BGE" means Baltimore Gas and Electric Company, a Maryland corporation, or its successor. "Committee" means the Committee on Management of the Board of Directors of BGE. "Compensation" means any retainer and meeting fees payable by BGE to a participant in his/her capacity as a Director. Compensation excludes expense reimbursements paid by BGE to a participant in his/her capacity as a Director. "Deferred Compensation" means any Compensation that is deferred under the provisions of this Plan. "Director" means a member of the Board of Directors of BGE. "Earnings" means earnings, appreciation, and/or depreciation, computed in the same manner as under the Employee Savings Plan. "Employee Savings Plan" means the Baltimore Gas and Electric Company Employee Savings Plan as may be amended from time to time. "Fixed Rate" means the equivalent of the rate earned by investments in the Fixed Rate Fund. "Plan Accounts" means amounts of a participant's Deferred Compensation and Earnings under the Plan. 3. PLAN ADMINISTRATION. The Plan is administered by the Manager, Staff Services Department of BGE, or the Manager succeeding to that function, who has sole authority (except as specified otherwise herein) to interpret the Plan, and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective. Appeals of written decisions by the Plan Administrator may be made to the Committee. Decisions by the Committee shall be final and not subject to further appeal. The Plan Administrator shall have the power to delegate all or any part of his/her duties to one or more designees, and to withdraw such authority, by written designation. 4. ELIGIBILITY AND PARTICIPATION. A Director who is not an employee of BGE or any of its subsidiaries is eligible to participate in the Plan by electing to defer Compensation, while so classified. Eligibility to participate shall terminate on the date the participant ceases to be a Director or the date the participant becomes an employee of BGE or any of its subsidiaries. Notwithstanding termination of eligibility, such person with Plan Accounts will remain a participant of the Plan, except that no further deferrals of Compensation under the Plan are permitted. 5. COMPENSATION DEFERRAL ELECTION. A participant may elect to defer all or a part of his/her Compensation. Such election shall specify the percentage or dollar amount of the Director's Compensation to be deferred. Such election shall be made by written notification to the Plan Administrator. Such election shall be made prior to the calendar year during which the applicable Compensation is payable, and shall be effective as of the first day of such calendar year. If a participant initially becomes eligible to participate in the Plan during a calendar year, the election for such calendar year must be made within 30 days after the date the participant initially becomes eligible to participate in the Plan, and shall be effective with respect to Compensation earned after the date the election is received by the Plan Administrator. Elections under this Section shall remain in effect for all succeeding calendar years until revoked. Elections may be revoked by written notification to the Plan Administrator, and shall be effective as of the first day of the calendar year following the calendar year during which the revocation is received by the Plan Administrator. 6. PLAN ACCOUNTS. Deferred Compensation is held for the benefit of each participant in the general assets of BGE, and shall be credited with Earnings at the Fixed Rate. Earnings are credited to Plan Accounts commencing on the date the applicable Deferred Compensation was credited to the Plan Accounts. 79 7. DISTRIBUTIONS OF PLAN ACCOUNTS. Distributions of Plan Accounts shall be made in cash only, from the general assets of BGE. A participant may elect to begin distributions in the year following the year that eligibility to participate terminates, or if later, in the year following the year in which a participant attains age 70. Such election must be made prior to the end of the calendar year in which eligibility to participate terminates. Alternatively, a participant who reaches age 70 while still eligible to defer Compensation under the Plan may elect to begin distributions, of amounts in his/her Plan Accounts as of the end of the year the participant reaches age 70, in the year following the year that the participant reaches age 70. Such election must be made prior to the end of the calendar year in which the participant reaches age 70, and a distribution election to receive any subsequently deferred amounts beginning in the year following the year that eligibility to participate terminates, must be made prior to the end of the calendar year in which eligibility to participate terminates. A participant may elect to receive distributions in a single payment or in annual installments during a period not to exceed ten years. The single payment or the first installment payment, whichever is applicable, shall be made within the first sixty (60) days of the calendar year elected for distribution. Subsequent installments, if any, shall be made within the first sixty (60) days of each succeeding calendar year until the participant's Plan Accounts have been paid. In the event applicable elections are not made, a participant shall receive a distribution in a single payment within the first sixty (60) days of the year following the year that eligibility to participate terminates. Earnings are credited to Plan Accounts through the date of distribution, and amounts held for installment payments shall continue to be credited with Earnings, as specified in Section 6. If a participant dies, the entire unpaid balance of his/her Plan Accounts shall be paid to the beneficiary or beneficiaries designated in writing by the participant or, if no designation was made, to the estate of the participant. Payment shall be made within sixty (60) days after notice of death is received by the Plan Administrator. Notwithstanding anything herein contained to the contrary, the Committee shall have the right in its sole discretion to vary the manner and timing of distributions of a participant entitled to a distribution under this Section 7, and may make such distributions in a single payment or over a shorter or longer period of time than that elected by a participant. 8. BENEFICIARIES. A participant shall have the right to designate a beneficiary or beneficiaries who are to receive a distribution pursuant to Section 7 in the event of the death of the participant. Any designation, change or recision of the designation shall be made by written notification to the Plan Administrator. The last designation of beneficiary received by the Plan Administrator shall be controlling over any testamentary or purported disposition by the participant, provided that no designation, recision or change thereof shall be effective unless received by the Plan Administrator prior to the death of the participant. If the designated beneficiary is the estate, or the executor or administrator of the estate, of the participant, a distribution pursuant to Section 7 may be made to the person(s) or entity (including a trust) entitled thereto under the will of the participant or, in the case of intestacy, under the laws relating to intestacy. 9. VALUATION OF PLAN ACCOUNTS. The Plan Administrator shall cause the value of a participant's Plan Accounts, at least once per year as of December 31, to be determined separately and be reported to the Company and the participant. Valuation of a participant's Plan Accounts shall be determined in accordance with the procedures contained in the Employee Savings Plan. 10. WITHDRAWALS. No withdrawals of Plan Accounts may be made, except a participant may at any time request a hardship withdrawal from his/her Plan Accounts. The request shall be made in writing to the Plan Administrator. Such hardship withdrawal will be permitted only with approval of the Plan Administrator. A hardship withdrawal will be permitted by the Plan Administrator only in the case of an unforeseeable emergency. An unforeseeable emergency is an unanticipated emergency that is caused by an event beyond the control of the participant that would result in severe financial hardship to the participant if the hardship withdrawal were not permitted. An unforeseeable emergency includes a severe financial hardship to the participant resulting from a sudden and unexpected illness or accident of the participant or of a dependent of the participant, loss of the participant's property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant. A hardship withdrawal may be permitted only to the extent reasonably necessary to satisfy the emergency need. The participant will receive payment after the Plan Administrator has had reasonable time to consider the request. 11. COPIES OF PLAN AVAILABLE. Copies of the Plan and any and all amendments thereto shall be made available to all participants during normal business hours at the office of the Plan Administrator. 80 12. MISCELLANEOUS. With respect to a participant's Plan Accounts, a participant has the status of a general unsecured creditor of BGE, and the plan constitutes a mere promise by BGE to make benefit payments in the future. It is the intention of BGE and each participant that the Plan be unfunded for tax purposes and for purposes of Title I of the Employee Retirement Income Security Act of 1974. A participant's Plan Accounts shall not be subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except (i) to the extent specially mandated and directed by applicable state or federal statute; and (ii) as requested by the participant or beneficiary to satisfy income tax withholding or liability. This Plan may be amended from time to time or suspended or terminated at any time, at the written direction of the Committee. However, amendments required to keep the Plan in compliance with applicable laws and regulations may be made by the Plan Administrator, on advice of counsel. No amendment to or termination of this Plan shall prejudice the rights of any participant or beneficiary entitled to receive payment hereunder at the time of such action. Participation in this Plan shall not constitute a contract of employment between BGE and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person. This Plan shall be governed in all respects by Maryland law. 81 EX-10 5 EXHIBIT 10(G) EXHIBIT 10(G) BALTIMORE GAS AND ELECTRIC COMPANY RETIREMENT PLAN FOR NON-EMPLOYEE DIRECTORS 1. OBJECTIVE. The objective of this Plan is to provide Non-Employee Directors of BGE with retirement benefits in recognition of their service on the Board of Directors of BGE, and to assist BGE in attracting and retaining individuals who are highly qualified to serve on the Board of Directors of BGE. 2. DEFINITIONS. As used herein, the following terms will have the meaning specified below: "Annual Retainer" means the amount payable by BGE to a Director as annual compensation for performance of services as a Director at the time of the Non-Employee Director's Retirement. All other amounts (including without limitation board/committee meeting fees, committee chair retainers, and expense reimbursements) shall be excluded in calculating the amount of the Annual Retainer. "BGE" means Baltimore Gas and Electric Company, a Maryland corporation, or its successor. "Director" means a member of the Board of Directors of BGE. "Non-Employee Director" means a Director who is not, and will never be, eligible to receive employee retirement benefits from BGE or any affiliated company. "Plan" means the BGE Retirement Plan for Non-Employee Directors. "Retirement" means ceases membership on the Board of Directors of BGE. 3. PLAN ADMINISTRATION. The Plan is administered by the Vice President -- Management Services of BGE, who has sole authority (except as specified otherwise herein) to interpret the Plan, and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective. The Plan Administrator shall have the power to delegate all or any part of his/her duties to one or more designees, and to withdraw such authority, by written designation. 4. ELIGIBILITY AND PARTICIPATION. A Non-Employee Director is eligible to participate in the Plan if he/she has served as a Director of BGE for at least five years prior to Retirement. 5. AMOUNT AND TIMING OF PLAN BENEFIT PAYOUT. An eligible participant is entitled to an annual benefit amount equal to the Annual Retainer. The Annual Retainer is payable in cash each year for life; however, no payments shall be made after a participant's death. Payment of the Annual Retainer to a participant who on his/her Retirement date is at least age 60 shall be made within the first sixty days of the applicable calendar year, beginning with the calendar year after his/her Retirement. Payment of the Annual Retainer to all other participants shall be made within the first sixty days of the applicable calendar year, beginning with the calendar year after the later to occur of his/her (1) 65th birthday, or (2) Retirement. The Plan Administrator may, in his/her sole discretion, vary the manner and timing of payments to participant. 6. COPIES OF PLAN AVAILABLE. Copies of the Plan and any and all amendments thereto shall be made available to all participants during normal business hours at the office of the Plan Administrator. 7. AMENDMENT; TERMINATION. This Plan may be amended from time to time or suspended or terminated at any time, at the written direction of the Board of Directors. However, amendments required to keep the Plan in compliance with applicable laws and regulations (including tax rules) may be made by the Plan Administrator, on advice of counsel. No amendment to or termination of this Plan shall prejudice the rights of any participant entitled to receive payment hereunder at the time of such action. 8. MISCELLANEOUS. With respect to Plan benefits, a participant has the status of a general unsecured creditor of BGE, and the Plan constitutes a mere promise by BGE to make benefit payments in the future. It is the intention of BGE and each participant that the Plan be unfunded for tax purposes and for purposes of Title I of the Employee Retirement Income Security Act of 1974. A participant's Plan benefits shall not be subject to alienation or assignment by any participant nor shall any of them be subject to attachment or garnishment or other legal process except to the extent specially mandated and directed by applicable state or federal statute. Participation in this Plan shall not constitute a contract of employment between BGE and any person and shall not be deemed to be consideration for, or a condition of, any person's employment by, or continual service as a Director of, BGE or any affiliated company. This Plan shall be governed in all respects by Maryland law. 82 EX-10 6 EXHIBIT 10(H) EXHIBIT 10(H) SUMMARY OF BALTIMORE GAS AND ELECTRIC COMPANY LONG TERM PERFORMANCE PROGRAM The Long Term Performance Program ("Program") was established in 1993. Cash awards under the Program will be based on corporate performance for a three year period. The initial awards under the Program will measure corporate performance for the years 1994 through 1996 and will be paid out in 1997. Performance will be measured by comparing the Baltimore Gas and Electric Company total shareholder return to the Dow Jones Electric Utilities Index total return. 83 EX-10 7 EXHIBIT 10(K) EXHIBIT 10(K) AMENDED SUMMARY 1992 LONG TERM INCENTIVE PLAN OF CONSTELLATION HOLDINGS, INC. PURPOSE The purpose of this plan is to provide a compensation vehicle to motivate and reward key senior executives of the Constellation Companies for the achievement of long-term business objectives. PERFORMANCE MEASUREMENT This is a five (5) year plan based on Constellation Holdings, Inc. having achieved at the end of the five (5) year period both, certain levels of net income and a return on equity that either equals or exceeds fourteen percent (14%). The chart below shows the award amounts each participant would be eligible to receive for achieving varying net income levels. The receipt of up to 30% of this amount would be based on individual/unit performance. Should the Company not achieve a Return on Equity of at least 14%, no part of this award will be paid. OTHER PLAN FEATURES The total award will be forfeited if employment termination occurs during the performance period except for reason of death, disability or retirement. Senior executives hired after the beginning of the first performance year, but prior to the end of the last performance year, may be eligible to participate on a prorated basis. At the end of the performance period the value of the award will be made in either cash or, if certain required approvals are obtained, in BGE common stock. All awards will be subject to tax withholding. Participation in the Plan does not constitute a contractual agreement regarding future employment or a contractual right to receive an award. The President and Chief Executive Officer of Constellation Holdings, Inc. participates, but is eligible for a prorated award equal to 50% of the amount determined under the terms of the Plan. 84 The graph illustrates the gross amount of award (vertical axis) available per participant based on Constellation Holdings, Inc. having achieved at the end of a five year period certain levels of net income (horizontal axis). No award is payable unless Constellation Holdings, Inc., achieves a return on equity of at least 14% at the end of the five year period. Awards range from $150,000 where five year net income equals at least $165 million, with a potential additional $50,000 award based on individual performance, to a $350,000 award for net income of at least $198 million, with a potential additional $200,000 award based on individual performance. 85 EX-12 8 EXHIBIT 12 EXHIBIT 12 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
12 MONTHS ENDED --------------------------------------------------------------- DECEMBER DECEMBER DECEMBER DECEMBER DECEMBER 1993 1992 1991 1990 1989 ----------- ----------- ----------- ----------- ----------- (IN THOUSANDS OF DOLLARS) Net Income................................................... $ 309,866 $ 264,347 $ 233,681 $ 175,446 $ 276,291 Taxes on Income.............................................. 140,833 105,994 88,041 22,818 84,704 ----------- ----------- ----------- ----------- ----------- Adjusted Net Income.......................................... $ 450,699 $ 370,341 $ 321,722 $ 198,264 $ 360,995 ----------- ----------- ----------- ----------- ----------- Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness............................... $ 199,415 $ 200,848 $ 213,616 $ 194,656 $ 167,503 Capitalized Interest....................................... 16,167 13,800 20,953 25,748 5,842 Interest Factor in Rentals................................. 2,144 2,033 1,801 1,840 2,388 ----------- ----------- ----------- ----------- ----------- Total Fixed Charges........................................ $ 217,726 $ 216,681 $ 236,370 $ 222,244 $ 175,733 ----------- ----------- ----------- ----------- ----------- Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends......................... $ 41,839 $ 42,247 $ 42,746 $ 40,261 $ 32,381 Income Tax Required........................................ 18,763 16,729 15,916 5,166 9,779 ----------- ----------- ----------- ----------- ----------- Total Preferred and Preference Dividend Requirements....... $ 60,602 $ 58,976 $ 58,662 $ 45,427 $ 42,160 ----------- ----------- ----------- ----------- ----------- Total Fixed Charges and Preferred and Preference Dividend Requirements................................................ $ 278,328 $ 275,657 $ 295,032 $ 267,671 $ 217,893 ----------- ----------- ----------- ----------- ----------- Earnings (2)................................................. $ 652,258 $ 573,222 $ 537,139 $ 394,760 $ 530,886 ----------- ----------- ----------- ----------- ----------- Ratio of Earnings to Fixed Charges........................... 3.00 2.65 2.27 1.78 3.02 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements............................ 2.34 2.08 1.82 1.47 2.44 - -------------------------- (1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings which would be required to meet dividend requirements on preferred stock and preference stock. (2) Earnings are deemed to consist of net income which includes earnings of BGE's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest.
85 EX-21 9 EXHIBIT 21 EXHIBIT 21 SUBSIDIARIES OF THE REGISTRANT*
JURISDICTION OF INCORPORATION ---------------- Constellation Holdings, Inc..................................................................................... Maryland BNG, Inc........................................................................................................ Delaware Safe Harbor Water Power Corporation............................................................................. Pennsylvania - -------------------------- *The names of certain directly owned subsidiaries have been omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary.
86 EX-23 10 EXHIBIT 23 EXHIBIT 23 CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS We consent to the incorporation by reference in the Prospectuses prepared in accordance with the requirements of Form S-8 (File No. 33-56084) and Forms S-3 (File Nos. 33-49801, 33-45260, 33-33559, 33-57658, 33-57704, 33-50329, 33-45258, and 33-50331) of our report dated January 21, 1994, which contains explanatory paragraphs related to the recoverability of replacement energy costs and changes in accounting methods, accompanying the consolidated financial statements and the consolidated financial statement schedules of Baltimore Gas and Electric Company as of December 31, 1993 and 1992 and for each of the three years in the period ended December 31, 1993, included in this Annual Report on Form 10-K of Baltimore Gas and Electric Company. /s/ Coopers & Lybrand -------------------------------------- COOPERS & LYBRAND Baltimore, Maryland March 18, 1994 87 -----END PRIVACY-ENHANCED MESSAGE-----