Annual Report (Form 10-K), fiscal year 1993

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.



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:
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.
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:
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
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
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.
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.
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:
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
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:
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).
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
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
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.
ELECTRIC OPERATING STATISTICS
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.
GAS OPERATING STATISTICS
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.
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.
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
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:
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.
ITEM 2. PROPERTIES
ELECTRIC: The principal electric generating plants of BGE are as follows:
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.

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.
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.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable.
ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officers of the Registrant are:
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.

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
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.

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.
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.
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.
BGE UTILITY REVENUES AND SALES
Electric revenues changed during 1993 and 1992 because of the following factors:
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.
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
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:
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:
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
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:
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:
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
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.
DIVERSIFIED BUSINESSES EARNINGS
Earnings per share from diversified businesses were:
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
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.
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.
ITEM 8.


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
CONSOLIDATED STATEMENTS OF INCOME
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation.
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation.
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation.
CONSOLIDATED STATEMENTS OF CASH FLOWS
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation.
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION (CONTINUED)
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation.
CONSOLIDATED STATEMENTS OF INCOME TAXES
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been restated to conform to the current year's presentation.
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.
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
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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
NOTE 2. SEGMENT INFORMATION
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.
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:
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:
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.
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.
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:
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.
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.
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.
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.
The following table sets forth the composition of net postretirement benefit cost.
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:
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.
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.
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.
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%.
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:
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:
WEIGHTED AVERAGE INTEREST RATES FOR VARIABLE RATE DEBT
The weighted average interest rates for variable rate debt during 1993 and 1992 were as follows:
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:
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.
The combined aggregate redemption requirements for all series of redeemable preference stock for each of the next five years are as follows:
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.
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:
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:
NOTE 12. TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes were as follows:
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
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:
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
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
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.
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
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.
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.
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10.



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.

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.

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.

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.

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,
Consolidated Balance Sheets at December 31, 1993 and December 31,
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:
Schedules other than those listed above are omitted as not applicable or not required.
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.
(b) Reports on Form 8-K: None
SCHEDULE V -- PROPERTY, PLANT AND EQUIPMENT
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.
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
YEAR 1993
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.
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR 1992
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.
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VI -- ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT YEAR 1991
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.
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VII -- GUARANTEES OF SECURITIES OF OTHER ISSUERS AS OF DECEMBER 31, 1993
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE VIII -- VALUATION AND QUALIFYING ACCOUNTS
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)
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.
EXHIBIT INDEX