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 two wholly owned subsidiaries of BGE, Constellation Holdings, Inc. and its subsidiaries (collectively, the Constellation Companies) and BGE Home Products & Services, Inc. (HPS) and its subsidiary Maryland Environmental Systems, Inc. (MES).
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: 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 8.
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 offices, 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 and 1994, 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 482 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. 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, 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, 1995, there were 81,056 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 1994 and 1993 in the amounts set forth below.
COMMON STOCK DIVIDENDS AND PRICE RANGES
*Based on New York Stock Exchange Composite Transactions as reported in the eastern edition of THE WALL STREET JOURNAL.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE CURRENT YEAR'S PRESENTATION.
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.
Effective July 1, 1994, BGE formed a wholly owned subsidiary, BGE Home Products & Services, Inc. (HPS), consisting of BGE's existing merchandise and gas and appliance service operations. HPS' revenues and expenses are included in diversified businesses revenues and diversified businesses selling, general, and administrative expenses, respectively. Prior-year amounts have been reclassified to conform with the current year's presentation.
RESULTS OF OPERATIONS
EARNINGS PER SHARE OF COMMON STOCK
Consolidated earnings per share were $1.93 for 1994 and $1.85 for 1993, an increase of $.08 and $.22 from prior-year amounts, respectively. The changes in earnings per share reflect a higher level of earnings applicable to common stock, offset partially by the larger number of outstanding common shares. The summary below presents the earnings-per-share amounts.
1994 1993 1992 Utility business $1.81 $1.77 $1.52 Diversified businesses .12 .08 .11 Total $1.93 $1.85 $1.63
EARNINGS APPLICABLE TO COMMON STOCK
Earnings applicable to common stock increased $15.7 million in 1994 and $45.9 million in 1993. The 1994 increase reflects higher utility and diversified businesses earnings. The 1993 increase reflects higher utility earnings, slightly offset by lower earnings from diversified businesses.
Utility earnings increased in 1994 compared to the prior year due to three principal factors: lower operations and maintenance expenses; an increase in the allowance for funds used during construction; and greater sales of electricity. The higher sales of electricity are primarily due to an increased number of customers compared to 1993. The 1994 earnings increase was offset partially by higher depreciation and amortization expense, which includes the write-off of certain Perryman costs (see discussion on page 29). Utility earnings increased in 1993 over 1992 because BGE sold more electricity than in the previous year and because of increased base rates. Three 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 offset partially by higher operations and maintenance expenses, depreciation and amortization expense, 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%.
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 favorably affected utility earnings through April 1994. Several electric fuel rate cases now pending before the PSC discussed in Notes 1 and 13 could also affect future years' earnings.
Future competition may also affect earnings in ways that are not possible to predict (see discussion on page 33).
Earnings from diversified businesses, which primarily represent the operations of Constellation Holdings, Inc. (CHI) and its subsidiaries (collectively, the Constellation Companies) and BGE Home Products & Services, Inc. (HPS), increased during 1994 and decreased during 1993. The reasons for these changes are discussed in the "Diversified Businesses Earnings" section on pages 30 and 31.
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 actual 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 for 1994 and 1993.
30-Year 1994 1993 Average Cooling degree days 949 865 804 Percentage change compared to prior year 9.7% 22.3% Heating degree days 4,670 4,959 4,901 Percentage change compared to prior year (5.8)% (0.3)%
BGE UTILITY REVENUES AND SALES
Electric revenues changed during 1994 and 1993 because of the following factors:
1994 1993 (IN MILLIONS) System sales volumes $ 9.9 $112.4 Base rates 1.4 58.5 Fuel rates (21.5) (55.0) Revenues from system sales (10.2) 115.9 Interchange sales 26.5 27.2 Other revenues (1.9) 3.5 Total electric revenues $ 14.4 $146.6
Electric system sales represent volumes sold to customers within BGE's service territory at rates determined by the PSC. These amounts exclude interchange sales, discussed separately later. Below is a comparison of the changes in electric system sales volumes.
1994 1993 Residential 0.5% 9.0% Commercial (0.4) 4.1 Industrial 17.8 2.7 Total 2.5 5.8
Sales to residential and commercial customers were essentially unchanged from the prior year due to three factors: the number of customers increased; higher sales from extreme weather conditions early in the year slightly exceeded lower sales from milder weather in the second half of the year; and usage-per-customer decreased. Sales to industrial customers reflect primarily an increase in the sale of electricity to Bethlehem Steel, which purchased more electricity from BGE due to increased steel production and the fact that Bethlehem Steel is now purchasing its full electricity requirements from BGE. Bethlehem Steel is still producing power with its own generating facility, but is now selling the output from this facility to BGE rather than using the power to reduce its requirements. Hotter summer weather was the main reason for the increase in total sales in 1993. The sales increases to the residential and commercial customers reflect significantly hotter summer weather, and to a lesser extent, increased usage and customer growth. Sales to the industrial class reflect increased sales of electricity to Bethlehem Steel to support its increased steel production during 1993.
Base rates increased slightly during 1994 due to the remaining effect of the PSC's April 1993 rate order, offset partially by the deferral of the portion of energy conservation surcharge billings subject to refund. Base rates increased in 1993 due to 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%.
Under the energy conservation surcharge, if the PSC determines that BGE is earning in excess of its authorized rate of return, BGE will have to refund (by means of lowering future surcharges) a portion of energy conservation surcharge revenues to its customers. The portion subject to the refund is compensation for foregone sales from conservation programs and incentives for achieving conservation goals and will be refunded to customers with interest beginning in the ensuing July when the annual resetting of the conservation surcharge rates occurs. BGE earned in excess of its authorized rate of return on electric operations for the period July 1, 1993 through June 30, 1994. As a result, BGE deferred the portion of electric energy conservation revenues subject to refund for the period December 1993 through November 1994. The deferral of these billings totaled $20.1 million.
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 1994 and 1993 due to a lower fuel rate, offset partially by increased electric system sales volumes. 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 previous year. BGE expects electric fuel rate revenues to remain relatively constant through 1995.
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 its own system sales of electricity, if BGE' s available generation is the least costly available to PJM utilities. Interchange sales increased during 1994 and 1993 because BGE had a less-costly generation mix than other PJM utilities. The less-costly mix reflects greater generation from the Brandon Shores Power Plant and the operation of the Calvert Cliffs Nuclear Power Plant.
Gas revenues decreased during 1994 and increased during 1993 because of the following factors:
1994 1993 (IN MILLIONS) Sales volumes $ 3.6 $ 0.6 Base rates 2.4 2.6 Gas cost adjustment revenues (16.1) 28.8 Other revenues (1.8) 0.8 Total gas revenues $ (11.9) $32.8
The changes in gas sales volumes compared to the year before were:
1994 1993 Residential 0.6% 2.5% Commercial (3.4) 2.2 Industrial 4.2 (5.8) Total 0.7 (0.6)
Total gas sales increased during 1994 because of higher sales to residential and industrial customers, offset partially by lower sales to commercial customers. Sales to industrial customers reflect primarily greater usage of natural gas by Bethlehem Steel. Sales to commercial and industrial customers were negatively impacted because delivery service customers either voluntarily switched their fuel source from natural gas to alternate fuels, or were involuntarily interrupted by BGE as a result of extreme winter weather conditions in the first quarter of 1994. Interruptible customers maintain alternate fuel sources and pay reduced rates in exchange for BGE's right to interrupt service during periods of peak demand. Total gas sales decreased during 1993 because of lower sales to industrial customers, offset partially 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 their L-Blast furnace. The increases in sales to the residential and commercial classes of customers reflect the colder winter weather during the first quarter of 1993 and an increase in the number of customers.
Base rates increased slightly in 1994 due to an increased recovery of eligible gas conservation program costs through the energy conservation surcharge. Base rates increased in 1993 for two 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 a return on BGE's higher level of gas rate base.
Changes in gas cost adjustment revenues result primarily from the operation of the purchased gas adjustment clauses which are designed to recover actual gas costs (see Note 1). Changes in gas cost adjustment revenues normally do not affect earnings. Gas cost adjustment revenues decreased during 1994 primarily because of decreased prices of purchased gas and slightly lower sales volumes subject to the clauses. Gas cost adjustment revenues increased during 1993 primarily because of increased prices to recover higher costs of purchased gas and higher sales volumes subject to gas cost adjustment clauses. Delivery service sales volumes are not subject to gas cost adjustment clauses because delivery service customers purchase their gas directly from third parties.
BGE UTILITY FUEL AND ENERGY EXPENSES
Electric fuel and purchased energy expenses were as follows:
1994 1993 1992 (IN MILLIONS) Actual costs $541.2 $483.9 $445.2 Net recovery of costs under electric fuel rate clause (see Note 1) 1.1 50.7 111.0 Total expense $542.3 $534.6 $556.2
Actual electric fuel and purchased energy costs increased during 1994 as a result of a more costly actual generation mix and an increase in the net output of electricity generated to meet the demand of BGE's system and the PJM system. The cost of the actual generation mix increased due to higher purchased energy costs and scheduled outages at the Calvert Cliffs Nuclear Power Plant in 1994. Actual electric fuel and purchased energy costs during 1993 increased for two 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.
Purchased gas expenses were as follows:
1994 1993 1992 (IN MILLIONS) Actual costs $222.7 $246.4 $213.6 Net (deferral) recovery of costs under purchased gas adjustment clause (see Note 1) 1.9 (3.7) 0.5 Total expense $224.6 $242.7 $214.1
Actual purchased gas costs decreased during 1994 for two reasons: lower gas prices and lower output associated with the decreased demand for BGE gas. The lower gas prices reflect market conditions and take-or-pay and other supplier refunds, offset by higher costs related to the implementation of Federal Energy Regulatory Commission (FERC) Order 636 and higher demand charges. Actual purchased gas costs increased in 1993 for three 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 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
In 1994, in order to more accurately reflect utility operations expense, BGE reclassified the amortization of deferred energy conservation expenditures and deferred nuclear expenditures from operations expense to depreciation and amortization expense. In addition, BGE reclassified diversified businesses' expenses from operations expense to diversified businesses-selling, general, and administrative expense. Prior-year amounts have been reclassified to conform with the current year's presentation.
Operations expense decreased during 1994 primarily due to labor savings achieved as a result of the Company's employee reduction programs discussed in Note 7 and continuing cost control efforts. These savings offset higher expense from the amortization of the cost of the 1993 and 1992 Voluntary Special Early Retirement Programs (VSERP) and a $10.0 million charge for a bonus paid to employees in lieu of a general wage increase. In addition, operations expense for 1994 decreased because operations expense for 1993 included a $17.2 million charge for certain employee reduction programs, offset partially by a credit to expense equivalent to the $9.8 million cost of termination benefits associated with the Company' s 1992 VSERP.
Operations expense increased during 1993 due to higher labor costs, employee reduction expenses (see Note 7), postretirement benefit expenses resulting from the implementation of Statement of Financial Accounting Standards No. 106 (see Note 6), and higher nuclear operating costs. These increases were offset partially by the 1993 reversal of the $9.8 million charge originally recorded in 1992 for termination benefits associated with the Company's 1992 VSERP to reflect the ratemaking treatment adopted by the PSC in its April 1993 rate order.
Operations expense is expected to be reduced in 1995 due to the realization of a full year of cost savings from the employee reduction programs and continuing cost control efforts. These lower costs are expected to exceed other increases in operations expenses.
Maintenance expense decreased during 1994 due primarily to lower costs at the Calvert Cliffs Nuclear Power Plant. Maintenance expense increased in 1993 because of higher labor costs and higher costs at the Calvert Cliffs Nuclear Power Plant.
Depreciation and amortization expense increased during 1994 because of the write-off of certain Perryman costs discussed below. Additionally, depreciation and amortization expense increased in 1994 and 1993 because of higher depreciable plant in service and higher levels of energy conservation program costs. The increase in depreciable plant in service resulted from the addition of electric transmission and distribution plant and certain capital additions at the Calvert Cliffs Nuclear Power Plant during 1994 and 1993.
Initially, BGE had planned to build two combined cycle generating units at its Perryman site. However, due to significant changes in the environment in which utilities operate, BGE now has no plans to construct the second combined cycle generating unit. Accordingly, during the third quarter of 1994, BGE wrote off $15.7 million of the costs associated with that second combined cycle unit. This write-off reduced after-tax earnings during 1994 by $11.0 million or 7 cents per share. Work on the first 140mw combustion turbine at Perryman continues to be on schedule for commercial operation in 1995.
Depreciation and amortization expense in 1995 will be affected by the completion of a facility-specific study of the cost to decommission the Calvert Cliffs Nuclear Power Plant. This study generated a higher decommissioning cost than the prior estimate which will increase depreciation expense $9 million annually. In addition, the PSC issued an order adjusting BGE' s utility plant depreciation rates to reflect the results of a detailed depreciation study. The new depreciation rates are expected to result in an increase in depreciation accruals of approximately $21 million annually. BGE plans to defer the increased depreciation accruals for recovery in a future base rate proceeding, consistent with previous rate actions of the PSC.
Taxes other than income taxes increased slightly during 1994 due primarily to higher property taxes resulting from higher levels of utility plant in service. Taxes other than income taxes increased during 1993 because of higher property taxes from the addition of Brandon Shores Unit 2 to the taxable base effective July 1, 1992, 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
The allowance for funds used during construction (AFC) increased during 1994 because of a higher level of construction work in progress which was offset partially by the lower AFC rate established by the PSC in the April 1993 rate order. AFC was essentially unchanged in 1993 because a higher level of construction work in progress was offset by the lower AFC rate discussed above.
Net other income and deductions increased in 1994 primarily due to a lower level of charitable contributions and gains realized on the sale of receivables.
Capitalized interest decreased during 1994 due to lower capitalized interest on the Constellation Companies' power generation systems, offset partially by the accrual by BGE of carrying charges on electric deferred fuel costs excluded from rate base (see Note 5). Capitalized interest increased during 1993 due to the accrual of carrying charges on electric deferred fuel costs excluded from rate base.
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 31.
DIVERSIFIED BUSINESSES EARNINGS
Earnings per share from diversified businesses were:
1994 1993 1992 Constellation Holdings, Inc. Power generation systems $ .10 $ .07 $ .08 Financial investments .03 .10 .09
Real estate development and senior living facilities (.03) (.04) (.05) Effect of 1993 Tax Act - (.04) - Other (.01) (.01) (.01) Total Constellation Holdings, Inc. .09 .08 .11 BGE Home Products & Services, Inc. .03 - - Total diversified businesses $ .12 $ .08 $ .11
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 increased in 1994 primarily due to payments for the curtailment of output at two wholesale power generating projects as discussed below. Power generation systems earnings during 1993 were essentially unchanged. Earnings for 1993 include $8.0 million of energy tax credits on the commercial operation of the Puna geothermal plant, offset by costs incurred at the Panther Creek waste-coal project in order to resolve fuel quality and other start-up problems.
The Constellation Companies' investment in wholesale power generating projects includes $177 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 rate for the first ten years of the agreements and at variable 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 subsequent to the inception of these agreements, 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 and pursuing
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 its ownership interests in the projects. Two of these wholesale power generating projects, in which the Constellation Companies' investment totals $27.4 million, have executed agreements with Pacific Gas & Electric (PG&E) providing for the curtailment of output through the end of the fixed price period in return for payments from PG&E. The payments from PG&E during the curtailment period will be sufficient to fully amortize the existing project finance debt. However, following the curtailment period, the projects remain contractually obligated to commence production of electricity at the avoided cost rates, which could result in reduced earnings or losses for the reasons described above. The Company cannot predict the impact that these matters regarding any of the 16 projects 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. Financial investment earnings decreased during 1994 due to reduced earnings from the investment portfolio. Additionally, 1993 results reflected a $6.1 million gain from the sale of a portion of an investment in a financial guaranty insurance company. Earnings increased slightly in 1993 as compared to 1992 because this gain was substantially offset by lower investment income 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.
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 increased slightly during 1994 due to gains recognized from the sale of two retail centers, an office building, and interests in two senior living facilities. The increases in diversified businesses' revenues and in selling, general, and administrative expenses reflect the proceeds of these sales and the cost of the facilities sold, respectively. Earnings from real estate development and senior living facilities were essentially unchanged in 1993 because a $2.1 million gain on the sale of a substantial portion of the 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 Constellation Companies' real estate portfolio has experienced continuing carrying costs and depreciation. Additionally, the Constellation Companies have been expensing rather than capitalizing interest on certain undeveloped land where development activities were at minimal levels. These factors have affected earnings negatively and are expected to continue to do so until the levels of undeveloped land are reduced. 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. To the extent the real estate market continues to improve, earnings from real estate activities are expected to improve also.
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 has improved, 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.
BGE Home Products & Services earnings increased during 1994 primarily due to a gain on the sale of receivables.
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 this Report under 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 1992 through 1994, along with estimated amounts for the years 1995 through 1997, 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 above. Electric construction expenditures include the installation of two 5,000 kilowatt diesel generators at Calvert Cliffs Nuclear Power Plant, one of which is scheduled to be placed in service in 1995 and the second in 1996; 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 expenditures do not include additional generating units.
During 1994, 1993, and 1992, the internal generation of cash from utility operations provided 72%, 71%, and 81% respectively, of the funds required for BGE's capital requirements exclusive of retirements and redemptions of debt and preference stock. In addition, in 1994, $70 million of cash was provided by the sale of certain BGE and HPS receivables (see Note 13). During the three-year period 1995 through 1997, the Company expects to provide through utility operations 100% 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, 1994, BGE's issuances of long-term debt, preference stock, and common stock were $1,557 million, $130 million, and $448 million, respectively. During the same period, retirements and redemptions of BGE's long-term debt and preference stock
totaled $1,425 million and $149 million, respectively, exclusive of any redemption premiums or discounts. 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 enhance the capital structure of Constellation Holdings, Inc.
DIVERSIFIED BUSINESSES CAPITAL REQUIREMENTS
DEBT AND LIQUIDITY
The Constellation Companies intend to meet capital requirements by refinancing debt as it comes due and through internally generated cash. These internal sources include cash that may be generated from operations, 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 31). 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 has entered into a $50 million revolving credit agreement.
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 1995 through 1997 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 amounts on page 32 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 institutional lenders.
RESPONSE TO REGULATORY CHANGE
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. In response to the competitive forces and regulatory changes, as discussed in Part 1 of this Report under the heading Regulatory Matters and Competition, BGE from time to time will consider various strategies designed to enhance its competitive position and to increase its ability to adapt to and anticipate regulatory changes in its utility business. These strategies may include internal restructurings involving the complete or partial separation of its generation, transmission and distribution businesses, acquisitions of related or unrelated businesses, business combinations, and additions to or dispositions of portions of its franchised service territories. BGE may from time to time be engaged in preliminary discussions, either internally or with third parties, regarding one or more of these potential strategies. No assurances can be given as to whether any potential transaction of the type described above may actually occur, or as to the ultimate effect thereof on the financial condition or competitive position of BGE.
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, 1994 and 1993, 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, 1994. These financial statements are the responsibility of the Company's Management. Our responsibility is to express an opinion on these financial statements 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, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
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 1989-1991 outages at the Company's nuclear power plant, and the Company established in 1990 a reserve of $35 million 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.
We have also previously audited, in accordance with generally accepted standards, the consolidated balance sheets and statements of capitalization at December 31, 1992, 1991, and 1990, and the related consolidated statements of income, cash flows, common shareholders' equity, and income taxes for each of the two years in the period ended December 31, 1991 (none of which are presented herein); and we expressed unqualified opinions on those consolidated financial statements. In our opinion, the information set forth in the Summary of Operations included in the Selected Financial Data for each of the five years in the period ended December 31, 1994, appearing on page 21 is fairly stated in all material respects in relation to the financial statements from which it has been derived.
/s/ Coopers and Lybrand L.L.P. COOPERS & LYBRAND L.L.P.
Baltimore, Maryland January 20, 1995
Consolidated Statements of Income
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE CURRENT YEAR'S PRESENTATION.
Consolidated Balance Sheets
AT DECEMBER 31, 1994 1993 (IN THOUSANDS) ASSETS Current Assets Cash and cash equivalents $ 38,590 $ 84,236 Accounts receivable (net of allowance for uncollectibles) 314,842 401,853 Fuel stocks 70,627 70,233 Materials and supplies 149,614 145,130 Prepaid taxes other than income taxes 57,740 54,237 Other 47,022 38,971 Total current assets 678,435 794,660
Investments and Other Assets Real estate projects 471,435 487,397 Power generation systems 311,960 298,514 Financial investments 224,340 213,315 Nuclear decommissioning trust fund 66,891 56,207 Safe Harbor Water Power Corporation 34,168 34,138 Senior living facilities 11,540 2,005 Other 58,824 65,355 Total investments and other assets 1,179,158 1,156,931
Utility Plant Plant in service Electric 5,929,996 5,713,259 Gas 616,823 557,942 Common 511,016 487,740 Total plant in service 7,057,835 6,758,941 Accumulated depreciation (2,305,372) (2,161,984) Net plant in service 4,752,463 4,596,957 Construction work in progress 506,030 436,440 Nuclear fuel (net of amortization) 134,012 139,424 Plant held for future use 24,320 24,066 Net utility plant 5,416,825 5,196,887
Deferred Charges Regulatory assets 773,034 768,125 Other 96,086 70,436 Total deferred charges 869,120 838,561
Total Assets $ 8,143,538 $7,987,039
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Consolidated Balance Sheets
AT DECEMBER 31, 1994 1993 (IN THOUSANDS) LIABILITIES AND CAPITALIZATION Current Liabilities Short-term borrowings $ 63,700 $ - Current portions of long-term debt and preference stock 323,675 44,516 Accounts payable 181,931 195,534 Customer deposits 24,891 22,345 Accrued taxes 19,585 20,623 Accrued interest 60,348 58,541 Dividends declared 66,012 63,966 Accrued vacation costs 30,917 35,546 Other 30,857 38,716 Total current liabilities 801,916 479,787
Deferred Credits and Other Liabilities Deferred income taxes 1,156,429 1,067,611 Deferred investment tax credits 149,394 157,426 Pension and postemployment benefits 138,835 183,043 Decommissioning of federal uranium enrichment facilities 45,836 46,858 Other 59,645 56,974 Total deferred credits and other liabilities 1,550,139 1,511,912
Capitalization Long-term debt 2,584,932 2,823,144 Preferred stock 59,185 59,185 Redeemable preference stock 279,500 342,500 Preference stock not subject to mandatory redemption 150,000 150,000 Common shareholders' equity 2,717,866 2,620,511 Total capitalization 5,791,483 5,995,340
Commitments, Guarantees, and Contingencies - See Note 13
Total Liabilities and Capitalization $8,143,538 $7,987,039
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Consolidated Statements of Cash Flows
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE CURRENT YEAR'S PRESENTATION.
Consolidated Statements of Common Shareholders' Equity
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Consolidated Statements of Capitalization
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Consolidated Statements of Capitalization
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
Consolidated Statements of Income Taxes
AT DECEMBER 31, 1994 1993 (DOLLAR AMOUNTS IN THOUSANDS) DEFERRED INCOME TAXES Deferred tax liabilities Accelerated depreciation $ 840,376 $ 789,165 Allowance for funds used during construction 208,726 202,490 Income taxes recoverable through future rates 93,952 90,950 Deferred termination and postemployment costs 53,749 55,890 Deferred fuel costs 41,507 45,518 Leveraged leases 31,948 32,613 Percentage repair allowance 36,630 35,431 Other 148,064 125,850 Total deferred tax liabilities 1,454,952 1,377,907 Deferred tax assets Alternative minimum tax 71,074 73,203 Accrued pension and postemployment benefit costs 51,163 64,065 Deferred investment tax credits 52,288 55,099 Other 123,998 117,929 Total deferred tax assets 298,523 310,296 Deferred income taxes per Consolidated Balance Sheets $1,156,429 $1,067,611
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
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), BGE Home Products & Services, Inc. (HPS) and BNG, Inc. are consolidated in the financial statements, and 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, respectively. 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 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 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.
Current tax expense consists solely of regular tax. In certain prior years, tax expense included an alternative minimum tax (AMT) that 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, 1994, this carryforward totaled $71.1 million.
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 businesses other than leveraged leases are flowed through to income.
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 AND OTHER ASSETS
The Company adopted Statement of Financial Accounting Standards No. 115 (Statement No. 115), "Accounting for Certain Investments in Debt and Equity Securities," effective January 1, 1994. Securities subject to the requirements of Statement No. 115 are reported at fair value as of December 31, 1994. Certain of Constellation Companies' marketable equity securities totaling $24.3 million are classified as trading securities. These securities are reported as other current assets, and unrealized gains and losses are included in diversified businesses revenues. The investments comprising the nuclear decommissioning trust fund and certain marketable equity securities of CHI are classified as available for sale. Unrealized gains and losses on these securities, as well as CHI's portion of unrealized gains and losses on securities of equity-method investees, are recorded in shareholders' equity. At December 31, 1993 marketable equity securities are stated at the lower of cost or market value.
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. Utility plant retired or otherwise disposed of is charged to accumulated depreciation. 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 straight-line rates applied to the average investment in classes of depreciable property. Vehicles are depreciated based on their estimated useful lives. Effective in 1995, BGE revised its utility plant depreciation rates to reflect the results of a detailed depreciation study. The new rates are expected to result in an increase in depreciation accruals of approximately $21 million annually.
Depreciation expense for 1994 includes the write-off of certain costs at BGE's Perryman site. Initially, BGE had planned to build two combined cycle generating units at this site. However, due to significant changes in the environment in which utilities operate, BGE now has no plans to construct the second combined cycle generating unit. Accordingly, during the third quarter of 1994, BGE wrote off $15.7 million of the costs associated with that second combined cycle unit. This write-off reduced after-tax earnings during 1994 by $11.0 million or 7 cents per share. Also in 1994, BGE reclassified the amortization of deferred energy conservation expenditures and deferred nuclear expenditures from operations expense to depreciation and amortization expense. Prior-year amounts have been reclassified to conform with the current year's presentation.
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 $143 million as of December 31, 1994. 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 sold. 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 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 $109.8 million and $93.4 million at December 31, 1994 and 1993, 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 have 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. The Company completed a facility-specific study in 1995 which generated an estimate of $521 million in 1993 dollars to decommission the radioactive portion of the plant. The Company plans to use the facility-specific cost estimate as a basis for recording decommissioning expense in 1995, for 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.
Prior to 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.
The Constellation Companies capitalize interest on qualifying real estate and power generation development projects. BGE capitalizes interest on carrying charges accrued 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.
ACCOUNTING STANDARDS ISSUED
The Financial Accounting Standards Board has issued Statement of Financial Accounting Standards Nos. 114 and 118, regarding accounting for impairment of a loan, effective January 1, 1995. Adoption of these statements is not expected to have a material impact on the Company's financial statements.
NOTE 2. SEGMENT INFORMATION
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE CURRENT YEAR'S PRESENTATION.
NOTE 3. SUBSIDIARY INFORMATION
Diversified businesses consist of the operations of Constellation Holdings, Inc. and its subsidiaries, BGE Home Products & Services, Inc. (HPS), and BNG, Inc. Diversified businesses' operating expenses have been reclassified as diversified businesses-selling, general, and administrative expense in the consolidated statements of income. Prior-year amounts have been reclassified to conform with the current year s presentation.
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.
Effective July 1, 1994, BGE formed a wholly owned subsidiary, BGE Home Products & Services, Inc., which engages in the businesses of appliance and consumer electronics sales and service; heating, ventilation, and air conditioning system sales, installation and service; and home improvements and services.
BNG, Inc. is a wholly owned subsidiary which engages in natural gas brokering.
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. The condensed financial information does not reflect the elimination of inter-company balances or transactions which are eliminated in the Company's consolidated financial statements.
1994 1993 1992 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Income Statements Revenues Real estate projects $ 106,915 $ 77,598 $ 76,582 Power generation systems 41,301 24,971 28,084 Financial investments 12,126 21,195 21,485 Total revenues 160,342 123,764 126,151 Expenses other than interest and income taxes 107,267 80,707 77,154 Income from operations 53,075 43,057 48,997 Interest expense (45,782) (47,845) (43,903) Capitalized interest 10,776 14,702 13,800` Income tax benefit (expense) (4,305) 1,984 (3,637) Net income $ 13,764 $ 11,898 $ 15,257 Contribution to the Company's earnings per share of common stock $ .09 $ .08 $ .11 Balance Sheets Current assets $ 53,034 $ 54,039 $ 29,899 Noncurrent assets 1,055,056 1,036,507 990,273 Total assets $1,108,090 $1,090,546 $1,020,172 Current liabilities $ 70,670 $ 24,201 $ 113,404 Noncurrent liabilities 718,846 759,048 611,370 Shareholders' equity 318,574 307,297 295,398 Total liabilities and shareholders' equity $1,108,090 $1,090,546 $1,020,172
NOTE 4. REAL ESTATE PROJECTS AND FINANCIAL INVESTMENTS
Real estate projects consist of the following investments held by the Constellation Companies:
AT DECEMBER 31, 1994 1993 (IN THOUSANDS) Properties under development $267,483 $249,473 Rental and operating properties (net of accumulated depreciation) 203,000 237,194 Other real estate ventures 952 730 Total $471,435 $487,397
Financial investments consist of the following investments held by the Constellation Companies:
AT DECEMBER 31, 1994 1993 (IN THOUSANDS) Insurance companies $ 87,700 $ 83,275 Marketable equity securities 51,175 42,681 Financial limited partnerships 48,014 44,903 Leveraged leases 37,451 38,669 Other securities - 3,787 Total $224,340 $213,315
The Constellation Companies' marketable equity securities and the investments comprising the nuclear decommissioning trust fund are classified as available for sale. The fair value and gross unrealized gains and losses for available for sale securities, exclusive of $3.2 million of unrealized net losses on securities of equity-method investees, are as follows:
Fair Unrealized Unrealized AT DECEMBER 31, 1994 Value Gains Loss (IN THOUSANDS) Marketable equity securities $ 51,175 $1,276 $1,859 U.S. government agency 5,102 - 113 State municipal bonds 58,034 929 2,599 Total $114,311 $2,205 $4,571
Contractual maturities of debt securities: (IN THOUSANDS) Less than 1 year $ - 1-5 years 13,855 5-10 years 46,010 More than 10 years 4,765 Total $64,630
Gross realized gains and losses on available for sale securities totaled $1.1 million and $3.1 million, respectively, in 1994. Net realized gains from financial investments totaled $6.5 million in 1993 and $9.8 million in 1992.
NOTE 5. REGULATORY ASSETS
Certain utility expenses normally reflected in income are deferred on the balance sheet as regulatory assets and liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers in utility revenues. The following table sets forth BGE's regulatory assets.
AT DECEMBER 31, 1994 1993 (IN THOUSANDS) Income taxes recoverable through future rates $268,436 $259,856 Deferred fuel costs 118,591 130,052 Deferred nuclear expenditures 90,937 86,726 Deferred termination benefit costs 79,979 96,793 Deferred postemployment benefit costs 73,591 62,892 Deferred cost of decommissioning federal uranium enrichment facilities 52,748 49,562 Deferred energy conservation expenditures 45,534 38,655 Deferred environmental costs 35,015 32,966 Other 8,203 10,623 Total $773,034 $768,125
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.
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 reduced as they are collected from customers.
The underrecovered costs deferred under the fuel clauses were as follows:
AT DECEMBER 31, 1994 1993 (IN THOUSANDS) Electric Costs deferred $152,815 $155,901 Reserve for possible disallowance of replacement energy costs (see Note 13) (35,000) (35,000) Net electric 117,815 120,901 Gas 776 9,151 Total $118,591 $130,052
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 1994 associated with nonrecurring phases of certain nuclear operations projects, and expenditures incurred during 1990 for investigating leaks in the pressurizer heater sleeves.
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 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 in 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 15-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 deferred fuel costs in excess of $72.8 million, net of related deferred income taxes. 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 and HPS. 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.
Prior service cost associated with retroactive plan amendments is amortized on a straight-line basis over the average remaining service period of active employees.
The Company's funding policy is to contribute at least the minimum amount required under Internal Revenue Service regulations using the projected unit credit cost method. Plan assets at December 31, 1994 consisted primarily of marketable fixed income and equity securities, group annuity contracts, and short-term investments.
The tables on page 49 set forth the combined funded status of the plans and the composition of total net pension cost. At December 31, 1994 and 1993, the accumulated pension obligation was greater than the fair value of the Pension Plan's assets. As a result, the Company recorded an additional pension liability, a portion of which was charged to shareholders' equity.
Net pension cost shown below does not include the cost of termination benefits described in Note 7.
AT DECEMBER 31, 1994 1993 (IN THOUSANDS) Vested benefit obligation $ 622,445 $ 677,069 Nonvested benefit obligation 8,838 11,359 Accumulated benefit obligation 631,283 688,428 Projected benefits related to increase in future compensation levels 82,815 109,161 Projected benefit obligation 714,098 797,589 Plan assets at fair value (614,284) (605,629) Projected benefit obligation less plan asset 99,814 191,960 Unrecognized prior service cost (23,863) (21,252) Unrecognized net loss (112,546) (148,450) Pension liability adjustment 52,177 58,553 Unamortized net asset from adoption of FASB Statement No. 87 1,586 1,812 Accrued pension liability $ 17,168 $ 82,623
YEAR ENDED DECEMBER 31, 1994 1993 1992 (IN THOUSANDS) Components of net pension cost Service cost-benefits earned during the period $ 15,015 $ 11,645 $ 11,771 Interest cost on projected benefit obligation 58,723 51,183 47,355 Actual return on plan assets 7,932 (56,225) (33,685) Net amortization and deferral (60,071) 6,591 (12,257) Total net pension cost 21,599 13,194 13,184 Amount capitalized as construction cost (2,578) (1,800) (1,839) Amount charged to expense $ 19,021 $ 11,394 $ 11,345
The Company also sponsors a defined contribution savings plan covering all eligible BGE employees and certain employees of the Constellation Companies and HPS. Under this plan, the Company makes contributions on behalf of participants. Company contributions to this plan totaled $8.7 million, $9.0 million, and $14.8 million in 1994, 1993, and 1992, 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 and HPS. 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.
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 20-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 in 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 postretirement 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 post-retirement benefit cost. Net postretirement benefit cost shown below does not include the cost of termination benefits described in Note 7.
YEAR ENDED DECEMBER 31, 1994 1993
(IN THOUSANDS) Net postretirement benefit cost: Service cost-benefits earned during the period $ 5,035 $ 4,373 Interest cost on accumulated postretirement benefit obligation 23,037 20,451 Amortization of transition obligation 11,700 12,021 Net amortization and deferral 646 - Total net postretirement benefit cost 40,418 36,845 Amount capitalized as construction cost (5,773) (5,898) Amount deferred (10,213) (11,965) Amount charged to expense $ 24,432 $ 18,982
Postretirement benefit costs recognized under the pay-as-you-go method in 1992 totaled $11.7 million, of which $1.9 million was capitalized and the remainder was charged to expense.
OTHER POSTEMPLOYMENT BENEFITS
The Company provides certain pay continuation payments and health and life insurance benefits to employees of BGE and certain employees of the Constellation Companies and HPS 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 $48 million and $52 million as of
December 31, 1994 and 1993, respectively. The portion of the December 31, 1993 liability attributable to regulated activities was deferred. The amounts deferred will be amortized over a 15-year period beginning in 1998. The adoption of Statement No. 112 did not have a material impact on net income.
ASSUMPTIONS
The pension and postemployment benefit liabilities were determined using the following assumptions.
AT DECEMBER 31, 1994 1993 Assumptions: Discount rate 8.5% 7.5% Average increase in future compensation levels 4.0% 4.5% Expected long-term rate of return on assets 9.0% 9.5%
The health care inflation rates for 1994 are assumed to be 9.0% for Medicare-eligible retirees and 11.5% 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 $35 million as of December 31, 1994 and would increase the aggregate of the service cost and interest cost components of postretirement benefit cost by approximately $4 million annually.
NOTE 7. TERMINATION BENEFITS
BGE 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 one-time 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.
BGE 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 one-time 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 is being 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 cost of termination benefits was charged to expense in 1993.
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. 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, HPS 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 5 1/2% Installment Series of 2002, 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 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 1996 and 1997. 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, 1994, BGE had no borrowings under these revolving credit agreements and had available $125 million of unused capacity under these agreements.
The Medium-term Notes Series A mature in February 1996. The weighted average interest rate for notes outstanding at December 31, 1994 is 8.22%.
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, 1994 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, 1994 is 7.16%.
The principal amounts of the 5 1/2% Installment Series Mortgage Bonds payable each year are as follows:
YEAR (IN THOUSANDS) 1995 through 1997 $ 605 1998 and 1999 690 2000 and 2001 865 2002 6,725
LONG-TERM DEBT OF CONSTELLATION COMPANIES
The mortgage and construction loans and other collateralized notes have varying terms. The $116.6 million of variable rate notes require periodic payment of principal and interest with various maturities from September 1995 through July 2009. The $13 million, 7.67% mortgage note requires monthly interest payments and is due October 1, 1995. The $6.2 million, 7.73% mortgage note requires quarterly principal and interest payments through March 15, 2009.
The unsecured notes outstanding as of December 31, 1994 mature in accordance with the following schedule:
AMOUNT (IN THOUSANDS) 8.35%, due August 28, 1995 $ 20,000 8.71%, due August 28, 1996 23,000 6.19%, due September 9, 1996 10,000 8.93%, due August 28, 1997 52,000 6.65%, due September 9, 1997 15,000 8.23%, due October 15, 1997 30,000 7.05%, due April 22, 1998 25,000 7.06%, due September 9, 1998 20,000 8.48%, due October 15, 1998 75,000 7.30%, due April 22, 1999 90,000 8.73%, due October 15, 1999 15,000 7.55%, due April 22, 2000 35,000 7.43%, due September 9, 2000 30,000 Total $440,000
The Constellation Companies entered into an unsecured revolving credit agreement on December 9, 1994 in the amount of $50 million. This agreement matures December 9, 1997 and will be used to provide liquidity for general corporate purposes. As of December 31, 1994, the Constellation Companies had no borrowings under this agreement.
WEIGHTED AVERAGE INTEREST RATES FOR VARIABLE RATE DEBT
The weighted average interest rates for variable rate debt during 1994 and 1993 were as follows:
1994 1993 BGE Floating rate series mortgage bonds 4.91% -% Pollution control loan 2.80 2.39 Port facilities loan 3.02 2.53 Adjustable rate pollution control loan 3.13 3.00 Economic development loan 3.00 2.49
Constellation Companies Mortgage and construction loans and other collateralized notes 7.27 6.26 Loans under credit agreements - 5.94
AGGREGATE MATURITIES
The combined aggregate maturities and sinking fund requirements for all of the Company's long-term borrowings for each of the next five years are as follows:
Constellation YEAR BGE Companies (IN THOUSANDS) 1995 $206,063 $ 56,112 1996 71,997 65,201 1997 80,653 125,389 1998 55,396 134,973 1999 251,467 116,425
NOTE 10. REDEEMABLE PREFERENCE STOCK
The 6.95%, 1987 Series and the 7.80%, 1989 Series are subject to mandatory redemption in their entirety at par on October 1, 1995 and July 1, 1997, respectively.
The following series are subject to an annual mandatory redemption of the number of shares shown below at par beginning in the year shown below. At BGE's option, an additional number of shares, not to exceed the same number as are mandatory, may be redeemed at par in any year, commencing in the same year in which the mandatory redemption begins. The 8.25%, 1989 Series, the 8.625%, 1990 Series, and the 7.85%, 1991 Series listed below are not redeemable except through operation of a sinking fund.
Beginning Series Shares Year 7.50%, 1986 Series 15,000 1992 6.75%, 1987 Series 15,000 1993 8.25%, 1989 Series 100,000 1995 8.625%, 1990 Series 130,000 1996 7.85%, 1991 Series 70,000 1997
The combined aggregate redemption requirements for all series of redeemable preference stock for each of the next five years are as follows:
YEAR (IN THOUSANDS) 1995 $61,500 1996 26,000 1997 83,000 1998 33,000 1999 33,000
With regard to payment of dividends or assets available in the event of liquidation, preferred stock ranks prior to preference and common stock; all issues of preference stock, whether subject to mandatory redemption or not, rank equally; and all preference stock ranks prior to common stock.
NOTE 11. LEASES
The Company, as lessee, contracts for certain facilities and equipment under lease agreements with various expiration dates and renewal options. Consistent with the regulatory treatment, lease payments for utility operations are charged to expense. Lease expense, which is comprised primarily of operating leases, totaled $12.7 million, $13.8 million, and $14.0 million for the years ended 1994, 1993, and 1992, respectively.
The future minimum lease payments at December 31, 1994 for long-term noncancelable operating leases are as follows:
YEAR (IN THOUSANDS) 1995 $ 4,185 1996 3,881 1997 3,447 1998 2,971 1999 1,409 Thereafter 5,347 Total minimum lease payments $21,240
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 22 years, with options to renew. The net book value of property under operating leases was $148.8 million at December 31, 1994. The future minimum rentals to be received under operating leases in effect at December 31, 1994 are as follows:
YEAR (IN THOUSANDS) 1995 $ 13,143 1996 12,233 1997 11,062 1998 9,718 1999 9,082 Thereafter 73,693 Total minimum rentals $128,931
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 1995 and subsequent years. In addition, BGE has entered into two long-term contracts for the purchase of electric generating capacity and energy. The contracts expire in 2001 and 2013. Total payments under these contracts were $69.4, $68.7, and $60.6 million during 1994, 1993, and 1992, respectively. At December 31, 1994, the estimated future payments for capacity and energy that BGE is obligated to buy under these contracts are as follows:
YEAR (IN THOUSANDS) 1995 $ 65,249 1996 62,880 1997 60,068 1998 60,699 1999 60,558 Thereafter 272,826 Total payments $582,280
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, 1994, the total amount of investment requirements committed to by the Constellation Companies is $43.6 million.
In December, 1994, BGE and HPS entered into agreements with a financial institution whereby BGE and HPS can sell on an ongoing basis up to an aggregate of $40 million and $50 million, respectively, of an undivided interest in a designated pool of customer receivables. Under the terms of the agreements, BGE and HPS have limited recourse on the receivables and have recorded a reserve for credit losses. At December 31, 1994, BGE and HPS had sold $30 million and $40 million of receivables, respectively, under these agreements.
GUARANTEES
BGE has agreed to guarantee two-thirds of certain indebtedness incurred by Safe Harbor Water Power Corporation. The amount of such indebtedness totals $35 million, of which $23.3 million represents BGE' s share of the guarantee. BGE assesses that the risk of material loss on the loans guaranteed is minimal.
As of December 31, 1994, the total outstanding loans and letters of credit of certain power generation and real estate projects guaranteed by the Constellation Companies were $31.2 million. Also, the Constellation Companies have agreed to guarantee certain other borrowings of various power generation and real estate projects. The Company has assessed 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 two titles designed to reduce emissions of sulfur dioxide and nitrogen oxide (NOx) from electric generating stations. Title IV contains provisions for compliance in two separate phases. Phase I of Title IV became effective January 1, 1995, and Phase II of Title IV must be implemented by 2000. BGE met the requirements of Phase I by installing flue gas desulfurization systems and fuel switching and through unit retirements. BGE is currently examining what actions will be required in order to comply with Phase II of the Act. 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 NOx control requirements under Title I of the Act are less certain because all implementation regulations have not yet been finalized by the government. It is expected that by the year 1999 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 and several state agencies that it is being considered a potentially responsible party (PRP) with respect to the cleanup of certain environmentally contaminated sites owned and operated by third parties. In addition, a subsidiary of Constellation Holdings, Inc. has been named as a defendant in a case concerning an alleged environmentally contaminated site owned and operated by a third party. Cleanup costs for these sites cannot be estimated, except that BGE's 15.79% share of the possible cleanup costs at one of these sites, Metal Bank of America, a metal reclaimer in Philadelphia, could exceed amounts recognized by up to approximately $14 million based on the highest estimate of costs in the range of reasonably possible alternatives. Although the cleanup costs for certain of the remaining 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 against BGE. BGE has recognized estimated environmental costs at these sites totaling $37.9 million as of December 31, 1994. These costs, net of accumulated amortization, have been deferred 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. BGE maintains various insurance policies for these contingencies. The costs that could result from a major accident or an extended outage at either of the Calvert Cliffs units could exceed the coverage limits.
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 $8.92 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 $6.08 million in any one year.
For physical damage to Calvert Cliffs, BGE has $2.75 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 $14.3 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 $473.2 million per unit of insurance, provided by the same industry mutual insurance company for replacement power costs. This amount can be reduced by up to $94.6 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 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. 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 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 its Calvert Cliffs Nuclear Power Plant. 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, is 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 value and fair value of financial instruments included in the Consolidated Balance Sheets.
Financial instruments included in current assets are cash and cash equivalents, net accounts receivable, trading securities, and miscellaneous loans receivable of the Constellation Companies. Financial instruments included in current liabilities represent total current liabilities from the balance sheet excluding accrued vacation costs. The carrying amount of current assets and current liabilities approximates fair value because of the short maturity of these instruments.
Investments and other assets include investments in common and preferred securities, which are classified as financial investments in the balance sheet, and the nuclear decommissioning trust fund. 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, 1994 and 1993 are excluded from the amounts shown in investments and other assets because it was not practicable to 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 $23.3 million and $17.0 million, respectively, at December 31, 1994 and $26.7 and $36.0 million, respectively, at December 31, 1993 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 FIRST QUARTER OF 1994 REFLECT A $10.0 MILLION ONE-TIME BONUS PAID TO EMPLOYEES IN LIEU OF A GENERAL INCREASE.
RESULTS FOR THE THIRD QUARTER OF 1994 REFLECT THE $15.7 MILLION ($11.0 MILLION AFTER-TAX) WRITE-OFF OF CERTAIN PERRYMAN COSTS (SEE NOTE 1).
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).
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.
CERTAIN PRIOR-YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM TO THE CURRENT YEAR'S PRESENTATION.
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 13 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 20, 1995 of Coopers & Lybrand L.L.P., Independent Auditors
Consolidated Statements of Income for three years ended December 31,
Consolidated Balance Sheets at December 31, 1994 and December 31,
Consolidated Statements of Cash Flows for three years ended December 31, 1994
Consolidated Statements of Common Shareholders' Equity for three years ended December 31, 1994
Consolidated Statements of Capitalization at December 31, 1994 and December 31, 1993
Consolidated Statements of Income Taxes for three years ended December 31, 1994
Notes to Consolidated Financial Statements
2. Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts
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.
*Incorporated by Reference. (b) Reports on Form 8-K: None
BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE II -- 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) By /s/ C. H. POINDEXTER Date: March 17, 1995 C. H. POINDEXTER CHAIRMAN OF THE BOARD
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.
EXHIBIT INDEX
*Incorporated by Reference. (b) Reports on Form 10-K: None