-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, KeJTW7OT+3FzuS/EDw6axXEC15fkZ8tJ4f2aFGrkVaUFd1QBbQC6js/MlTmP82ea nb8chZLMjwsgUSIjz/Xdew== 0000950169-97-000233.txt : 19970329 0000950169-97-000233.hdr.sgml : 19970329 ACCESSION NUMBER: 0000950169-97-000233 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970328 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BALTIMORE GAS & ELECTRIC CO CENTRAL INDEX KEY: 0000009466 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 520280210 STATE OF INCORPORATION: MD FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-01910 FILM NUMBER: 97566544 BUSINESS ADDRESS: STREET 1: GAS & ELECTRIC BLDG STREET 2: CHARLES CTR CITY: BALTIMORE STATE: MD ZIP: 21201 BUSINESS PHONE: 4107835920 10-K 1 BALTIMORE GAS & ELECTRIC CO. UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K -------------- ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES AND EXCHANGE ACT OF 1934 For the fiscal year ended 1-1910 December 31, 1996 Commission file number
-------------- BALTIMORE GAS AND ELECTRIC COMPANY (Exact name of registrant as specified in its charter) MARYLAND 52-0280210 (State of incorporation) (I.R.S. Employer Identification No.) 39 W. LEXINGTON STREET, BALTIMORE, MARYLAND 21201 (Address of principal executive offices) (Zip Code)
410-783-5920 (Registrant's telephone number, including area code) SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- New York Stock Exchange, Inc. Common Stock -- Without Par Value Chicago Stock Exchange, Inc. Pacific Stock Exchange, Inc. Preference Stock, Cumulative, $100 Par Value: 7.78%, 1973 Series 7.50%, 1986 Series Philadelphia Stock Exchange, Inc. 6.75%, 1987 Series
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: Not Applicable Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days. Yes x No . --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Aggregate market value of Common Stock, without par value, held by non-affiliates as of February 28, 1997 was approximately $4,045,549,228 based upon New York Stock Exchange composite transaction closing price. COMMON STOCK, WITHOUT PAR VALUE -- 147,667,114 SHARES OUTSTANDING ON FEBRUARY 28, 1997. TABLE OF CONTENTS
PAGE PART I Item 1 -- Business Overview of Consolidated Business........................................................... 1 Consolidated Capital Requirements........................................................... 3 Electric Business Electric Regulatory Matters and Competition............................................... 4 Electric Rate Matters..................................................................... 5 Nuclear Operations........................................................................ 6 Electric Load Management, Energy, and Capacity Purchases.................................. 7 Fuel for Electric Generation.............................................................. 8 Electric Operating Statistics............................................................. 10 Gas Business Gas Operating Statistics.................................................................. 11 Gas Regulatory Matters and Competition.................................................... 12 Gas Operations............................................................................ 12 Gas Rate Matters.......................................................................... 13 Franchises.................................................................................. 13 Diversified Businesses...................................................................... 13 Environmental Matters....................................................................... 17 Employees................................................................................... 19 Item 2 -- Properties.................................................................................. 20 Item 3 -- Legal Proceedings........................................................................... 21 Item 4 -- Submission of Matters to a Vote of Security Holders......................................... 21 PART II Item 5 -- Market for Registrant's Common Equity and Related Stockholder Matters....................... 22 Item 6 -- Selected Financial Data..................................................................... 23 Item 7 -- Management's Discussion and Analysis of Financial Condition and Results of Operations................................................................................. 24 Item 8 -- Financial Statements and Supplementary Data................................................. 34 Item 9 -- Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................................................................................. 58 PART III Item 10 -- Directors and Executive Officers of the Registrant.......................................... 58 Item 11 -- Executive Compensation...................................................................... 62 Item 12 -- Security Ownership of Certain Beneficial Owners and Management.............................. 69 Item 13 -- Certain Relationships and Related Transactions.............................................. 69 PART IV Item 14 -- Exhibits, Financial Statement Schedules and Reports on Form 8-K............................. 70 Signatures................................................................................................. 74
PART I ITEM 1. BUSINESS OVERVIEW OF CONSOLIDATED BUSINESS Baltimore Gas and Electric Company and Subsidiaries together are called the Company in this Report. The Company conducts utility operations through Baltimore Gas and Electric Company, called BGE in this Report. The Company is engaged in a number of diversified businesses through subsidiaries. BGE was incorporated under the laws of the State of Maryland on June 20, 1906. BGE is qualified to do business in the District of Columbia where its federal affairs office is located. BGE is qualified to do business in the Commonwealth of Pennsylvania where it is participating in the ownership and operation of two electric generating plants as described under ITEM 2. PROPERTIES. BGE also owns two-thirds of the outstanding capital stock, including one-half of the voting securities, of Safe Harbor Water Power Corporation, a hydroelectric producer on the Susquehanna River at Safe Harbor, Pennsylvania. (SEE ITEM 2. PROPERTIES -- ELECTRIC.) OVERVIEW OF UTILITY BUSINESS Our utility business consists primarily of generating, purchasing, and selling electricity and purchasing, transporting, and selling natural gas. The focus of these activities is serving customers in BGE's service territory. BGE furnishes electric and gas retail services in the City of Baltimore and in all or part of ten counties in Central Maryland. The electric service territory includes an area of approximately 2,300 square miles with an estimated population of 2,650,000. The gas service territory includes an area of more than 600 square miles with an estimated population of 2,000,000. There are no municipal or cooperative bulk power markets within BGE's service territory. As discussed throughout this report, the two units at BGE's Calvert Cliffs Nuclear Power Plant are its principal generating facilities and have the lowest fuel cost in BGE's system. An extended shutdown of either of these Units could have a substantial adverse effect on the Company's business and financial condition. (See NUCLEAR OPERATIONS and NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS for information regarding prior outages at the Plant.) For further information about utility operations see five other sections in this report -- ELECTRIC BUSINESS, ELECTRIC OPERATING STATISTICS, GAS OPERATING STATISTICS, GAS BUSINESS, and FRANCHISES. Competition and the Pending Merger The utility industry is facing potentially substantial regulatory change designed to foster competition in the provision of gas and electric services. The restructuring of the industry was a key consideration for BGE and Potomac Electric Power Company (PEPCO) agreeing to merge (the Merger). PEPCO is a neighboring electric utility serving Washington, D.C. and major portions of Montgomery and Prince George's Counties in Maryland. It is currently anticipated that the Merger will be completed during the first six months of 1997. The reasons for the Merger and other information about the Merger are discussed in more detail under ELECTRIC REGULATORY MATTERS AND COMPETITION and in the Registration Statement on Form S-4 (Registration No. 33-64799) which is included as an exhibit to this report by incorporation by reference. In response to the competitive forces and regulatory changes in the utility industry, BGE (and after the Merger the new company to be named Constellation EnergyTM Corporation) 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, other internal restructurings, mergers or acquisitions of utility or non-utility businesses, additions to or dispositions of portions of its franchised service territories, and spin-off or distribution of one or more businesses. BGE and its subsidiaries may from time to time be engaged in preliminary discussions, either internally or with third parties, about one or more of these potential strategies. It is not possible to predict the ultimate effect competition will have on BGE's earnings in future years. These matters are discussed under ELECTRIC REGULATORY MATTERS AND COMPETITION and GAS REGULATORY MATTERS AND COMPETITION. 1 OVERVIEW OF DIVERSIFIED BUSINESSES The Company is engaged in diversified businesses through three groups of subsidiaries: BGE Corp. and its subsidiaries -- these businesses include energy marketing activities, specifically power marketing, natural gas brokering, energy services, and district heating and cooling projects; Constellation(TM) Holdings and its subsidiaries (called the "Constellation Companies" in this report) -- these businesses include power generation outside BGE's service territory, investment activities, real estate, and senior-living facilities; and BGE Home Products & Services, Inc. and its subsidiary -- these businesses include appliance sales and service, heating and air conditioning sales and service, and home improvement. Our diversified businesses are described in more detail under the heading DIVERSIFIED BUSINESSES. OPERATING REVENUES AND INCOME The percentages of Operating Revenues and Operating Income attributable to electric, gas, and diversified operations are set forth below:
OPERATING REVENUES OPERATING INCOME* ------------------ ----------------- ELECTRIC GAS DIVERSIFIED ELECTRIC GAS DIVERSIFIED -------- --- ----------- -------- --- ----------- 1996.......................................... 70% 16 % 14% 75% 10 % 15% 1995.......................................... 76 14 10 83 7 10 1994.......................................... 76 15 9 85 4 11 1993.......................................... 77 16 7 87 6 7 1992.......................................... 77 16 7 82 8 10
*Net of income taxes. BGE currently derives approximately 22% of electric revenues and 40% of gas revenues from customers located in the City of Baltimore and 78% and 60%, respectively, from outside the City of Baltimore. No single customer's electric revenues exceed 4% of total electric revenues and no single customer's gas revenues exceed 4% of total gas revenues. The disparity between the percentage of gas operating revenues in relation to the percentage of gas operating income as compared to the same percentages for electric operations is due to BGE's level of investment and its fuel costs in each of these segments. BGE's operating revenue amounts represent recovery of all fuel and operating expenses plus a return on its investment in the business. BGE's net investment for ratemaking purposes in the electric business is $4.8 billion while the comparable investment in its gas business is approximately $605 million. Thus, operating revenues include a much greater return component for electric operations than gas operations. Also, as can be seen by referring to ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA, CONSOLIDATED STATEMENTS OF INCOME, gas purchased for resale as a percentage of gas revenues (55%) is greater than electric fuel and purchased energy as a percentage of electric revenues (25%). It should be noted that both purchased gas costs (prior to October 1996) and electric fuel costs are passed through to the customer with no mark-up for profit. Effective October 1996, the Maryland Commission approved a Market Based Rates incentive mechanism for pricing gas. This mechanism is discussed in GAS REGULATORY MATTERS AND COMPETITION. The combined effects of these factors yield the observed relationship between operating revenues and income for electric operations. 2 CONSOLIDATED CAPITAL REQUIREMENTS The Company's actual capital requirements for 1994 through 1996, along with estimated amounts for 1997 through 1999, are set forth below.
1994 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- ---- (IN MILLIONS) Utility Business Capital Requirements Construction expenditures (excluding AFC) Electric.................................................... $ 345 $ 223 $ 219 $ 230 $ 216 $ 215 Gas......................................................... 68 70 84 72 70 73 Common...................................................... 42 51 46 33 39 37 ----- ----- ----- ----- ----- ------- Total construction expenditures........................... 455 344 349 335 325 325 AFC (a)........................................................ 34 22 10 7 7 7 Nuclear fuel (uranium purchases and processing charges)........ 42 46 47 49 50 50 Deferred energy conservation expenditures (b).................. 41 46 31 24 19 18 Deferred nuclear expenditures (b).............................. 8 -- -- -- -- -- Retirement of long-term debt and redemption of preference stock....................................................... 203 279 184 173 117 270 ----- ----- ----- ----- ----- ------- Total utility business capital requirements............... 783 737 621 588 518 670 ----- ----- ----- ----- ----- ------- Diversified Business Capital Requirements........................ 88 173 170 322 345 391 ----- ----- ----- ----- ----- ------- Total capital requirements................................ $ 871 $ 910 $ 791 $ 910 $ 863 $ 1,061 ===== ===== ===== ===== ===== =======
(a) Allowance for Funds Used During Construction (AFC) is accrued for all construction projects with a construction period of more than one month. (See NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of AFC.) (b) See NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS for a discussion of deferred nuclear expenditures and deferred energy conservation expenditures. Utility business capital requirements do not reflect costs to complete the pending Merger with PEPCO. These costs, currently estimated to be $150 million, are discussed in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS. BGE's actual capital requirements may vary from the estimates set forth above because of a number of factors such as inflation, economic conditions, regulation, legislation, load growth, environmental protection standards, and the cost and availability of capital. Additionally, actual capital requirements may vary from the estimates set forth above because adjustments which may result from the pending Merger with PEPCO have not been reflected in those estimates. The capital requirements for diversified businesses may vary from the estimates set forth above due to a number of factors including market and economic conditions. The capital requirements for these businesses are discussed in detail in two sections of this report: DIVERSIFIED BUSINESS CAPITAL REQUIREMENTS and ITEM 7. MD&A -- CAPITAL REQUIREMENTS OF OUR DIVERSIFIED BUSINESSES. BGE's estimated construction, nuclear fuel, and deferred energy conservation expenditures are expected to amount to approximately $1.6 billion, $245 million, and $100 million, respectively, for the five-year period 1997-2001. Electric construction expenditures reflect improvements in BGE's existing generating plants and its transmission and distribution facilities. Future electric construction expenditures do not include additional generating units. During the period January 1, 1992 through December 31, 1996, BGE expended $2.0 billion for gross additions to utility plant or approximately 25% of its total utility plant (exclusive of nuclear fuel) at December 31, 1996. During the same period, a total of $423 million of utility plant was retired. Nuclear fuel expenditures include uranium purchases and processing charges. BGE presently estimates that approximately $1.1 billion will be required for retirements and redemptions of long-term debt (including sinking fund payments) and BGE preference stock during the five-year period 1997-2001. This estimate does not consider the proposed Merger with PEPCO. For further information with respect to capital requirements and for a discussion of internal generation of cash, see ITEM 7. MD&A -- LIQUIDITY AND CAPITAL RESOURCES. 3 ELECTRIC BUSINESS BGE's electric utility business in Maryland provides the major portion of revenues and earnings to the consolidated company. This business is discussed below in six sections titled ELECTRIC REGULATORY MATTERS AND COMPETITION; ELECTRIC RATE MATTERS; NUCLEAR OPERATIONS; ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES; FUEL FOR ELECTRIC GENERATION; AND ELECTRIC OPERATING STATISTICS. BGE recently announced its intention to enter the electric power marketing business through a subsidiary, which is discussed under the heading DIVERSIFIED BUSINESSES. ELECTRIC REGULATORY MATTERS AND COMPETITION In recent years BGE focused strategic attention to developments in federal regulatory policy which are designed to increase competition in the wholesale market for bulk power and expand competition in the market for generation. In 1993, the BGE Board of Directors formed the Long Range Strategy Committee to provide an oversight role in the development of BGE's long range strategic goals and to consider strategic initiatives which Management wished to present to the BGE Board. Many of these developments were prompted by the Energy Policy Act of 1992 (the 1992 Act), which granted the Federal Energy Regulatory Commission (FERC) the authority to order electric utilities to provide transmission service to other utilities and to other buyers and sellers of electricity in the wholesale market. The 1992 Act also created a new class of power producers, exempt wholesale generators, which are exempt from regulation under the Public Utility Holding Company Act of 1935, as amended (the 1935 Act). This exemption has increased the number of entrants into the electric generation market. Other developments resulted from policies at the Securities and Exchange Commission (SEC), which has liberalized its interpretation and administration of the 1935 Act in ways that have made mergers between utility companies less burdensome, thereby facilitating the creation of larger industry competitors. Moreover, state regulatory bodies in certain states had initiated proceedings to review the basic structure of the industry. Against this background, BGE and PEPCO agreed to merge in September 1995. Each company independently reached the conclusion that key factors contributing to success in a more competitive environment will be maintaining low-cost production and achieving a size that will enable it to continue to provide high quality customer service, enhancing its competitive position and attaining a greater level of financial strength. BGE, PEPCO, and Constellation Energy Corporation (formerly named R.H. Acquisition Corp.) entered into the Agreement and Plan of Merger dated as of September 22, 1995 (the Merger Agreement). The Merger Agreement provides that upon the receipt of all necessary approvals (including shareholder approval -- obtained in 1996 -- and a number of regulatory approvals -- several of which are still pending) BGE and PEPCO will be merged into Constellation Energy Corporation (the Merger). Constellation Energy Corporation is a shell corporation formed for the sole purpose of accomplishing the Merger. It is currently anticipated that all such approvals will be obtained during the first six months of 1997. The status of these approvals through the date of this report is found in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS. Preliminary estimates by the managements of PEPCO and BGE indicate that the synergies resulting from the combination of their utility operations could generate net cost savings of up to $1.3 billion over a period of 10 years following the Merger. These estimates indicate that about two-thirds of the savings will come from reduced labor costs, with the remaining savings split between nonfuel purchasing and corporate and administrative programs. These savings are expected to be allocated among shareholders and customers. This allocation will depend upon the results of regulatory proceedings in the various jurisdictions in which BGE and PEPCO operate their utility businesses. The reasons for the Merger, the terms and conditions contained in the Merger Agreement, and other matters concerning the Merger, PEPCO, and Constellation Energy Corporation are discussed in more detail in the Registration Statement on Form S-4 (Registration No. 33-64799) which is included as an exhibit to this Report on Form 10-K by incorporation by reference. The analyses employed in order to develop estimates of potential savings as a result of the Merger were necessarily based upon various assumptions which involve judgments with respect to, among other things, future national and regional economic and competitive conditions, inflation rates, regulatory treatment, weather conditions, financial market conditions, interest rates, future business decisions and other uncertainties, all of which are difficult to predict and many of which are beyond the control of BGE and PEPCO. Accordingly, while BGE believes that such assumptions are reasonable for purposes of the development of estimates of 4 potential savings, there can be no assurance that such assumptions will approximate actual experience or that all such savings will be realized. State regulators around the United States are also redefining the regulatory scheme for the electric utility industry. The Maryland Public Service Commission (Maryland Commission), after hearings in 1995 to consider electric utility restructuring, the impact of competition, regulatory reform and possible scenarios ranging from limited to full competition, had concluded that wholesale competition remains in the best interests of the state's energy consumers in view of the availability of efficient, reliable, comparatively low-cost power. During 1996 the pace of other states' actions to allow retail competition accelerated and two neighboring states, Pennsylvania and New Jersey, initiated retail competition schemes. In light of these activities, in 1996 the Maryland Commission started a new inquiry on retail competition and requested during 1997 both: (Bullet) recommendations from its staff, and (Bullet) filings from electric utilities with customers in Maryland to show how unbundled electric rates might be structured. The first analysis of retail competition by the District of Columbia Public Service Commission is currently in progress. At the date of this report, we do not expect any final action from the Maryland or District of Columbia Commissions regarding retail competition during 1997. It is not possible to predict the ultimate effect competition will have on BGE's earnings in the future. ELECTRIC RATE MATTERS ENERGY CONSERVATION SURCHARGE The Maryland Commission approved a base rate surcharge effective July 1, 1992 which provides for the recovery of deferred energy conservation expenditures, a return thereon, lost revenues, and incentives for achievement of predetermined goals for certain conservation programs subject to an earnings test. Effective April 1996 this earnings test is performed on an annual basis. All or a portion of the compensation for foregone sales due to conservation programs and the incentives for achieving conservation goals must be refunded to customers if BGE is earning in excess of its authorized rate of return, as determined by the Maryland Commission. (See discussion in ITEM 7. MD&A -- RESULTS OF OPERATIONS.) The surcharge is reset on July 1 of each year. ELECTRIC FUEL RATE PROCEEDINGS By statute, electric fuel costs are recoverable if the Maryland Commission finds that BGE demonstrates that, among other things, it has maintained the productive capacity of its generating plants at a reasonable level. The Maryland Commission 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. The Maryland Commission has established a Generating Unit Performance Program (GUPP) to measure annual utility compliance with maintaining the productive capacity of generating plants at reasonable levels by establishing a system-wide generating performance target and individual performance targets for each base load generating unit. As a result, actual generating performance, after adjustment for planned outages, is compared to the system-wide target and, if met, should signify compliance with the requirements of Maryland law. Failure to meet the system-wide target will result in review of each unit's adjusted actual generating performance versus its performance target in determining compliance with the law, and the basis for possibly imposing a penalty on BGE. Failure to meet these targets requires BGE to demonstrate that the outages causing the failure are not the result of mismanagement. Parties to fuel rate hearings may still question the prudence of BGE's actions or inactions with respect to any given generating plant outage, which could result in a disallowance of replacement energy costs. BGE is involved in fuel rate proceedings annually where issues concerning individual plant outages can be raised. Recovery of a portion of replacement energy costs has been denied in past proceedings and BGE cannot estimate the amount that could be denied in future fuel rate proceedings, but such amounts could be material. (See NUCLEAR OPERATIONS.) 5 BGE is required to submit to the Maryland Commission the actual generating performance data for each calendar year 45 days after year end. The Maryland Commission reviews BGE's performance for each calen- dar year in the first fuel rate proceeding initiated following the submission of the actual generating performance data for that year. BGE must initiate fuel rate proceedings in any month following a month during which the calculated fuel rate decreased by more than 5% and may initiate fuel rate proceedings in any month following a month during which the calculated fuel rate increased by more than 5%. NUCLEAR OPERATIONS Discussed below are certain events relating to the operations of the Calvert Cliffs Nuclear Power Plant (the Plant) during the period 1987 to the present, including issues involving the possible disallowance of replacement energy costs incurred during unplanned outages at the Plant. All outstanding issues will be resolved in fuel rate proceedings before the Maryland Commission which are conducted in accordance with the procedures outlined above under ELECTRIC RATE MATTERS -- ELECTRIC FUEL RATE PROCEEDINGS. OPERATIONS IN 1987 The Plant generated 10,069,576 megawatt hours (MWH) in 1987 which resulted in a capacity factor of 70%. In October 1988, BGE filed a fuel rate application for a change in its electric fuel rate under GUPP, which covered BGE's operating performance in 1987. This was the first proceeding filed under this program and BGE's filing demonstrated that it met the system-wide and individual plant performance targets for 1987, including the performance target for the Plant. BGE believed, therefore, it was entitled to recover all fuel costs incurred in 1987 without any disallowances. However, People's Counsel alleged that a number of the outages at the Plant, including the 66-day outage to document compliance with NRC mandated environmental qualification requirements, were due to management imprudence and requested that the Maryland Commission disallow recovery of the associated replacement energy costs which BGE estimated to be approximately $33 million. On January 23, 1995, the Hearing Examiner issued his decision in the 1987 fuel rate proceeding and found that the Company had met the GUPP standard which establishes a presumption that BGE had operated the Plant at a reasonably productive capacity level. However, the Order found that the presumption of reasonableness could be overcome by a showing of mismanagement and that such a showing was made with respect to the environmental qualifications outage time. In mitigation for meeting the GUPP standard, the Hearing Examiner disallowed replacement energy costs recovery for 15.5 days of the 66-day outage time. The Hearing Examiner's Order was appealed to the Maryland Commission by both BGE and People's Counsel. The Maryland Commission upheld the Hearing Examiner's findings with respect to the environmental qualification related outage time, but disagreed with certain methodologies applied by the Hearing Examiner. The impact of the Maryland Commission's decision on the Company's 1996 earnings was approximately $4.5 million. People's Counsel has filed a motion for rehearing. OPERATIONS IN 1988 The Plant generated 11,733,900 MWH in 1988 which resulted in a capacity factor of 81%. BGE filed a fuel rate application under GUPP in May, 1989 in which it demonstrated that it met the system-wide and individual plant performance targets for 1988. People's Counsel alleged that BGE imprudently managed several outages at the Plant and requested that the Maryland Commission disallow recovery of $2 million of replacement energy costs. On November 14, 1991, a Hearing Examiner at the Maryland Commission issued a proposed Order, which became final on December 17, 1991 and concluded that no disallowance was warranted. The Hearing Examiner found that BGE maintained the productive capacity of the Plant at a reasonable level, noting that it produced a near record amount of power and exceeded the GUPP standard. Based on this record, the Order concluded there was sufficient cause to excuse any avoidable failures to maintain productive capacity at higher levels. OPERATIONS IN 1989 TO 1991 -- EXTENDED OUTAGE The Plant generated 2,719,197 MWH in 1989 and 1,251,416 MWH in 1990. In the Spring of 1989, a leak was discovered around the Unit 2 pressurizer heater sleeves during a refueling outage. BGE shut down Unit 1 as a precautionary measure on May 6, 1989 to inspect for similar leaks and none were found at that time. However, Unit 1 was out of service for the remainder of 1989 and 285 days of 1990 to undergo maintenance and modification work to enhance the reliability of various safety systems, to repair equipment, and to perform required periodic surveillance tests. Unit 2 remained out of service until May 4, 1991 to 6 complete repair of the pressurizer, perform maintenance and modification work, and complete the refueling. The replacement energy costs associated with these extended outages for both Units at Calvert Cliffs, concluding with the return to service of Unit 2, were estimated at $458 million. This estimate was based on a computer simulation comparing the actual operating conditions during the extended outages with operating conditions assuming the Plant ran at its targeted capacity factor. The extended outages experienced at the Plant were reviewed by the Maryland Commission in the 1989-1991 fuel rate proceeding, and People's Counsel and others challenged recovery of some part of the associated replacement energy costs. Extended litigation followed about the amount of replacement energy costs BGE should be permitted to recover. In December 1996, BGE entered into a settlement agreement with People's Counsel and the Maryland Commission Staff proposing a resolution to all fuel rate issues during the 1989-1991 period. The Maryland Commission approved the settlement agreement in early 1997. BGE agreed that ratepayers will not fund a total of $118 million of electric replacement energy costs associated with the extended outages. This represents $83 million in addition to the $35 million reserve for possible disallowance of replacement energy costs recorded in 1990. Therefore, in December 1996, BGE increased the provision for the disallowance of such costs by $83 million. Additionally, in 1996, BGE wrote off $5.6 million of accrued carrying charges related to the deferred fuel balances. The remainder of the replacement energy costs associated with the extended outage had already been recovered from customers through the fuel rate. OPERATIONS SUBSEQUENT TO 1991 The Plant generated 10,663,950 MWH in 1992, which resulted in a capacity factor of 74%. There were no contested performance issues based on 1992 performance and BGE's GUPP filings were approved as filed. The Plant generated 12,300,816 MWH in 1993, which resulted in a capacity factor of 85%. In 1994, the Plant generated 11,225,977 MWH achieving a capacity factor of 77%. Review of the GUPP filings in 1993 and 1994 have been completed. There were no significant performance issues in either of these years and BGE's GUPP filings were approved as filed. The plant generated 12,940,496 MWH in 1995, which resulted in a capacity factor of 88%. The plant generated 12,069,937 MWH in 1996, which resulted in a capacity factor of 82%. A review of 1995 and 1996 performance will be initiated with BGE's next fuel rate application. ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES BGE has implemented various active load management programs designed to be used when system operating conditions require a reduction in load. These programs include customer-owned generation and curtailable service for large commercial and industrial customers, air conditioning control which is available to residential and commercial customers, and residential water heater control. The load reductions typically have been invoked on peak summer days; potential reduction in the Summer 1997 peak load from active load management is approximately 475 megawatts (MW). Cost recovery for these load management programs is attainable through the inclusion in rate base of capital investments and the appropriate expenses (including credits on customer bills) for recovery in base rate proceedings. The generating and transmission facilities of BGE are interconnected with those of neighboring utility systems to form the Pennsylvania-New Jersey-Maryland Interconnection (PJM). Under the PJM agreement, the interconnected facilities are used for substantial energy interchange and capacity transactions as well as emergency assistance. In addition, BGE enters into short-term capacity transactions at various times to meet PJM obligations. BGE has an agreement with Pennsylvania Power & Light Company (PP&L) to purchase a mix of energy and capacity from June 1, 1990 through May 31, 2001. This agreement, which has been accepted by the FERC, is designed to help maintain adequate reserve margins through this decade and provide flexibility in meeting capacity obligations. The PP&L agreement entitles BGE to 5.94% of the energy output, and net capacity (currently 130 MW), of PP&L's nuclear Susquehanna Steam Electric Station from October 1, 1991 to May 31, 2001 and also enables BGE to treat a portion of PP&L's capacity as BGE's capacity for purposes of satisfying BGE's installed capacity requirements as a member of the PJM. BGE is not acquiring an ownership interest in any of PP&L's generating units. PP&L will continue to control, manage, operate, and maintain that station and all other PP&L-owned generating facilities. BGE's firm capacity purchases at 7 December 31, 1996 represented 170 MW of rated capacity of Bethlehem Steel Corporation's Sparrows Point complex, 57 MW of rated capacity of the Baltimore Refuse Energy Systems Company, and the 130 MW of Susquehanna capacity from PP&L. In 1994 PECO Energy won a competitive bidding program to supply 140 MW for firm electric capacity and associated energy for 25 years beginning June 1, 1998. This contract has been accepted by both FERC and the Maryland Commission. FUEL FOR ELECTRIC GENERATION Information regarding BGE's electric generation by fuel type and the cost of fuels in the five-year period 1992-1996 is set forth in the following tables:
AVERAGE COST OF FUEL CONSUMED GENERATION BY FUEL TYPE ((CENTS) PER MILLION BTU) ------------------------------------ ---------------------------------------------- 1996 1995 1994 1993 1992 1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Nuclear (a)................... 40% 43% 39% 43% 40% 47.29 47.22 52.06 53.01 45.54 Coal.......................... 58 57 56 55 54 143.80 148.64 148.64 151.85 154.76 Oil........................... 1 1 3 3 1 313.33 267.59 245.28 253.36 254.19 Hydro & Gas................... 4 3 3 3 3 -- -- -- -- -- --- --- --- --- --- 103 104 101 104 98 Interchange/ Purchases (b)............... (3) (4) (1) (4) 2 --- --- --- --- --- 100% 100% 100% 100% 100% === === === === ===
(a) Nuclear fuel costs provide for disposal costs associated with long-term off-site spent fuel storage and shipping, currently set by law at one mill per kilowatt-hour of nuclear generation (approximately 10 cents per million Btu) and for contributions to a fund for decommissioning and decontaminating the Department of Energy's uranium enrichment facility. (See FUEL FOR ELECTRIC GENERATION -- NUCLEAR.) (b) Net purchases from (sales to) others. COAL: BGE obtains a large amount of its coal under supply contracts with mining operators. The remainder of its coal requirements are obtained through spot purchases. BGE believes that it will be able to renew such contracts as they expire or enter into similar contractual arrangements with other coal suppliers. BGE's Brandon Shores Units 1 and 2 have a total annual requirement of approximately 3,500,000 tons of coal (combined) with a sulfur content of less than approximately 0.8%. BGE's Crane Units 1 and 2 have a total annual requirement of about 700,000 tons of coal (combined) with a low ash melting temperature. BGE's Wagner Units 2 and 3 have a total annual requirement of approximately 900,000 tons of coal (combined) with a sulfur content of no more than 1%. Coal deliveries to BGE's coal burning facilities are made by rail and barge. The coal used by BGE is produced from mines located in central and northern Appalachia. BGE has a 20.99% undivided interest in the Keystone coal-fired generating plant and a 10.56% undivided interest in the Conemaugh coal-fired generating plant. The bulk of the annual coal requirements for the Keystone plant is under contract from Rochester and Pittsburgh Coal Company. The Conemaugh plant purchases coal from local suppliers on the open market. OIL: Under normal burn practices, BGE's requirements for residual fuel oil amount to approximately 1,000,000 barrels of low-sulfur oil per year. Deliveries of residual fuel oil are made directly into BGE barges from the suppliers' Baltimore Harbor marine terminal for distribution to the various generating plant locations. 8 NUCLEAR: The supply of fuel for nuclear generating stations involves the acquisition of uranium concentrates, its conversion to uranium hexafluoride, enrichment of uranium hexafluoride, and the fabrication of nuclear fuel assemblies. Information is set forth below with respect to fuel for Calvert Cliffs Units 1 and 2: Uranium Concentrates: BGE has, either in inventory or under contract, sufficient quantities of uranium to meet at least 90% of its requirements through 2000 and approximately 70% of its requirements between 2001 and 2004. Conversion: BGE has contractual commitments providing for the conversion of uranium concentrates into uranium hexafluoride which will meet approximately 90% of its requirements through 2000 and approximately 65% between 2001 and 2004. Enrichment: BGE has a contract with the U.S. Energy Corporation for the enrichment of 100% of BGE's enrichment requirements through 1998, declining to approximately 50% by 2004. Fuel Assembly Fabrication: BGE has contracted for the fabrication of fuel assemblies for reloads it requires through 2000.
The nuclear fuel market is very competitive and BGE does not anticipate any problem in meeting its requirements beyond the periods noted above. Expenditures for nuclear fuel are discussed in ITEM 7. MD&A -- LIQUIDITY AND CAPITAL RESOURCES. STORAGE OF SPENT NUCLEAR FUEL: Under the Nuclear Waste Policy Act of 1982 (the 1982 Act), spent fuel discharged from nuclear power plants, including Calvert Cliffs, is required to be placed into a federal repository. Such facilities do not currently exist, and, consequently, must be developed and licensed. BGE cannot now predict when such facilities will be available, although the 1982 Act obligates the federal government to accept spent fuel starting in 1998. While BGE cannot now predict what the ultimate cost will be, the 1982 Act assesses a one mill per kilowatt-hour fee on nuclear electricity generated and sold. At anticipated operating levels, it is expected that this fee will be approximately $13 million for Calvert Cliffs each year. In December 1996, the United States Department of Energy (DOE) notified BGE and other nuclear utilities that it is unable to meet the 1998 deadline for accepting spent fuel. BGE is participating in litigation, along with 36 other utilities, against the DOE. The litigation, titled NORTHERN STATES POWER, ET AL. V. DOE, was filed January 31, 1997 in the United States Court of Appeals for the D.C. Circuit. That Court has original jurisdiction under the 1982 Act. The utilities are requesting that the court allow them to pay fees, that formerly went directly to DOE, into escrow instead. Among other remedies, they seek to force DOE to submit a program with milestones illustrating how DOE will meet the deadline for accepting spent nuclear fuel and a monthly report to allow the utilities to monitor DOE's progress. Maryland law makes it unlawful to establish within the State a facility for the permanent storage of high-level nuclear waste, unless otherwise expressly required by federal law. BGE has received a license from the NRC to operate its on-site independent spent fuel storage facility. BGE now has storage capacity at Calvert Cliffs that will accommodate spent fuel from operations through the year 2006. In addition, BGE can expand its temporary storage capacity to meet future requirements until federal storage is available. COSTS FOR DECOMMISSIONING URANIUM ENRICHMENT FACILITIES: The Energy Policy Act of 1992 (the 1992 Act) contains provisions requiring domestic utilities to contribute to a fund for decommissioning and decontaminating the Department of Energy's (DOE) uranium enrichment facilities. These contributions are generally payable over a fifteen-year period with escalation for inflation and are based upon the amount of uranium enriched by DOE for each utility through 1992. The 1992 Act provides that these costs are recoverable through utility service rates as a cost of fuel. Information about the cost of decommissioning is discussed in NOTE 1 TO CONSOLIDATED FINANCIAL STATEMENTS under the heading "UTILITY PLANT, DEPRECIATION AND AMORTIZATION, AND DECOMMISSIONING." GAS: BGE has a firm natural gas transportation entitlement of 3,500 dekatherms a day to provide ignition and banking at certain power plants. Gas for electric generation is purchased as needed in the spot market using interruptible transportation arrangements. Certain gas fired units can use residual fuel oil as an alternative. 9 ELECTRIC OPERATING STATISTICS
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------ 1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- Electric Output (In Thousands) -- MWH: Generated................................ 30,107 30,548 28,413 28,907 25,626 Purchased (A)............................ 7,560 7,403 6,270 3,643 4,323 ---------- ---------- ---------- ---------- ---------- Subtotal............................ 37,667 37,951 34,683 32,550 29,949 Less Interchange and Other Sales......... 7,580 8,149 5,684 4,149 3,180 ---------- ---------- ---------- ---------- ---------- Total Output........................ 30,087 29,802 28,999 28,401 26,769 ========== ========== ========== ========== ========== Power Generated and Purchased at Times of Peak Load (MW) (one hour): Generated by Company..................... 4,789 5,162 3,384 5,245 3,679 Net Purchased (A)........................ 1,166 785 2,654 631 1,879 ---------- ---------- ---------- ---------- ---------- Peak Load (B)............................ 5,955 5,947 6,038 5,876 5,558 ========== ========== ========== ========== ========== Annual System Load Factor (%).............. 57.5 57.2 54.7 55.2 54.8 Revenues (In Thousands) Residential.............................. $ 958,736 $ 955,239 $ 931,711 $ 931,643 $ 839,954 Commercial............................... 861,343 879,438 852,989 869,829 842,694 Industrial............................... 207,579 208,441 205,611 199,042 201,950 ---------- ---------- ---------- ---------- ---------- System Sales............................. 2,027,658 2,043,118 1,990,311 2,000,514 1,884,598 Interchange and Other Sales.............. 155,877 166,964 118,027 91,543 64,323 Other.................................... 25,492 21,029 19,083 20,090 16,611 ---------- ---------- ---------- ---------- ---------- Total............................... $2,209,027 $2,231,111 $2,127,421 $2,112,147 $1,965,532 ========== ========== ========== ========== ========== Sales (In Thousands) -- MWH: Residential.............................. 11,243 10,966 10,670 10,614 9,735 Commercial............................... 12,591 12,635 12,351 12,395 11,909 Industrial............................... 4,596 4,591 4,433 3,763 3,663 ---------- ---------- ---------- ---------- ---------- System Sales............................. 28,430 28,192 27,454 26,772 25,307 Interchange and Other Sales.............. 7,580 8,149 5,684 4,149 3,180 ---------- ---------- ---------- ---------- ---------- Total............................... 36,010 36,341 33,138 30,921 28,487 ========== ========== ========== ========== ========== Customers Residential.............................. 995,197 988,179 978,591 968,212 956,570 Commercial............................... 104,501 103,399 101,957 100,820 99,673 Industrial............................... 4,261 4,161 3,967 3,800 3,761 ---------- ---------- ---------- ---------- ---------- Total............................... 1,103,959 1,095,739 1,084,515 1,072,832 1,060,004 ========== ========== ========== ========== ========== Average Cost of Fuel Consumed ((cents) per million Btu)............................. 108.05 104.78 112.44 112.77 110.20 ========== ========== ========== ========== ==========
BGE achieved an all-time peak load of 6,038 megawatts on January 19, 1994. (A) Includes purchases from Safe Harbor Water Power Corporation, a hydroelectric company, of which the Company owns two-thirds of the capital stock. (B) See ELECTRIC LOAD MANAGEMENT, ENERGY, AND CAPACITY PURCHASES for a discussion of active load management programs which may be activated at times of peak load. 10 GAS OPERATING STATISTICS
YEAR ENDED DECEMBER 31, -------------------------------------------------------- 1996 1995 1994 1993 1992 ---- ---- ---- ---- ---- Gas Output (In Thousands) -- DTH: Purchased.......................................... 70,260 70,391 68,541 71,221 70,211 LNG Withdrawn from Storage......................... 904 815 698 725 742 Produced........................................... 784 528 828 259 92 -------- -------- -------- -------- -------- Total Output.................................. 71,948 71,734 70,067 72,205 71,045 Delivery service gas (A)........................... 45,964 43,854 41,897 38,521 41,048 Off-system sales (B)............................... 10,204 -- -- -- -- -------- -------- -------- -------- -------- Total......................................... 128,116 115,588 111,964 110,726 112,093 ======== ======== ======== ======== ======== Peak Day Sendout (DTH)............................... 708,966 706,287 761,900 657,700 609,200 ======== ======== ======== ======== ======== Capability on Peak Day (DTH)......................... 870,000 847,000 847,000 847,000 847,000 Revenues (In Thousands) Residential........................................ $320,105 $248,283 $262,736 $265,601 $242,737 Commercial Excluding Delivery Service...................... 125,052 109,859 121,005 121,832 112,147 Delivery Service................................ 7,217 3,696 2,285 3,287 3,591 Industrial Excluding Delivery Service...................... 17,064 16,730 20,140 22,250 21,123 Delivery Service................................ 14,598 16,332 9,635 12,920 14,290 -------- -------- -------- -------- -------- System sales....................................... 484,036 394,900 415,801 425,890 393,888 Off-system sales................................... 26,600 -- -- -- -- Other.............................................. 6,656 5,604 5,448 7,273 6,511 -------- -------- -------- -------- -------- Total......................................... $517,292 $400,504 $421,249 $433,163 $400,399 ======== ======== ======== ======== ======== Sales (In Thousands) -- DTH: Residential........................................ 43,784 40,211 40,279 40,029 39,042 Commercial Excluding Delivery Service...................... 22,698 23,612 23,712 23,830 23,478 Delivery Service................................ 8,755 6,982 6,490 7,428 7,102 Industrial Excluding Delivery Service...................... 2,887 4,102 4,410 5,298 5,314 Delivery Service................................ 36,201 35,925 33,837 31,390 33,638 -------- -------- -------- -------- -------- System sales....................................... 114,325 110,832 108,728 107,975 108,574 Off-system sales................................... 10,204 -- -- -- -- -------- -------- -------- -------- -------- Total......................................... 124,529 110,832 108,728 107,975 108,574 ======== ======== ======== ======== ======== Customers Residential........................................ 516,523 506,739 498,152 491,165 486,863 Commercial......................................... 38,861 38,422 37,891 37,518 37,000 Industrial......................................... 1,350 1,334 1,354 1,353 1,412 -------- -------- -------- -------- -------- Total......................................... 556,734 546,495 537,397 530,036 525,275 ======== ======== ======== ======== ========
BGE achieved an all-time peak day sendout of 761,900 DTH on January 19, 1994. (A) Represents gas purchased by customers directly from suppliers for which BGE receives a fee for transportation through its system ("delivery service"). (See ITEM 7. MD&A -- RESULTS OF OPERATIONS.) (B) Represents gas sold to suppliers and end users of natural gas outside BGE's service territory (beginning first quarter 1996). (See ITEM 7. MD&A -- RESULTS OF OPERATIONS). Certain prior year amounts have been reclassified to conform with the current year's presentation. 11 GAS BUSINESS BGE's gas utility business in Maryland is discussed on the previous page under GAS OPERATING STATISTICS and below in three sections titled REGULATORY MATTERS AND COMPETITION; GAS OPERATIONS; AND GAS RATE MATTERS. BGE also has a subsidiary that is active in the gas marketing business, which is discussed under the heading DIVERSIFIED BUSINESSES. GAS REGULATORY MATTERS AND COMPETITION Regulatory changes in the natural gas business are well under way. In 1992, the Federal Energy Regulatory Commission (FERC) issued Order 636, which unbundled gas-service elements. This gave gas users the ability to choose various gas purchasing, transportation, brokering, and storage options. Prior to Order 636, BGE purchased gas, transportation and storage services primarily from pipeline companies. Now, BGE and other local distribution companies buy gas directly from various suppliers and arrange separately for transportation and storage. BGE's large gas customers are arranging for their own gas supplies and are contracting with BGE for transportation. The Maryland Commission continues to encourage BGE and other utilities to offer options for unbundling the gas services offered by local distribution companies and allowing smaller customers to arrange for their own gas supplies. As part of its response to the increase in competition in the natural gas business, BGE has obtained approval from the Maryland Commission to utilize profit sharing for earnings from off-system gas sales and capacity release revenues, and to implement a Market Based Rates (MBR) incentive gas purchasing mechanism. Off-system gas sales are direct sales to suppliers and end users of natural gas outside BGE's service territory. BGE makes these sales as part of a program to balance its supply of, and cost of, natural gas. Under the MBR mechanism, differences between a market index and BGE's actual cost of gas are shared equally between BGE's customers and shareholders. GAS OPERATIONS BGE distributes natural gas purchased directly from several producers and marketers. Transportation to BGE's city gate for these purchases is provided by Columbia Gas Transmission Corporation (Columbia), CNG Transmission Corporation (CNG), and Transcontinental Gas Pipe Line Corporation under various transportation agreements. BGE has upstream transportation capacity under contract on Tennessee Gas Pipeline Company, Texas Eastern Transmission Corporation, Columbia Gulf Transmission Company and ANR Pipeline Company (ANR). BGE has storage service agreements with Columbia, CNG and ANR. The transportation and storage agreements are on file with the Federal Energy Regulatory Commission (FERC). BGE's current pipeline firm transportation entitlements to serve its firm loads are 291,731 dekatherms (DTH) per day during the winter period and 266,731 DTH per day during the summer period. BGE uses the firm transportation capacity to move gas from the Gulf of Mexico, Louisiana, south central regions of Texas and Canada to BGE's city gate. The gas is subject to a mix of long and short-term contracts that are managed to provide economic, reliable and flexible service. Additional short-term contracts or exchange agreements with other gas companies can be arranged in the event of short-term emergencies. BGE has two market area storage contracts to manage weather sensitive gas demand during the winter period. Current maximum storage entitlements are 181,866 DTH per day. To supplement BGE's gas supply at times of heavy winter demands and to be available in temporary emergencies affecting gas supply, BGE has propane air and liquefied natural gas facilities. The liquefied natural gas facility consists of a plant for the liquefaction and storage of natural gas with a storage capacity of 1,000,000 DTH and a planned daily capacity of 287,988 DTH. The propane air facility consists of a plant with a mined cavern and refrigerated storage facilities having a total storage capacity equivalent to 1,000,000 DTH and a daily capacity of 85,000 DTH. BGE has under contract sufficient volumes of propane for the operation of the propane air facility and is capable of liquefying sufficient volumes of natural gas during the summer months for operation of its liquefied natural gas facility during winter periods. BGE offers gas for sale to its residential, commercial and industrial customers on a firm and interruptible basis. BGE also provides its commercial and industrial customers with a transportation service across its distribution system so that these customers may make direct purchase and transportation arrangements with 12 suppliers and pipelines. Customers with 250 DTH or more of annual gas consumption may make direct purchase and transportation arrangements. BGE also plans to conduct a pilot transportation program for up to 25,000 residential customers beginning in November 1997. A transportation fee is charged by BGE that is equivalent to its operating margin on gas it sells to similar customers for the service from the city gate to the customer's facility. This program enables BGE to maintain throughput at a level which assures that fixed costs are spread over the maximum number of DTH. BGE is authorized by the Maryland Commission to provide balancing and gas brokering services for its transportation customers and to bundle pipeline capacity with gas for off-system sales. GAS RATE MATTERS On November 20, 1995, the Maryland Commission issued an Order (the 1995 Rate Order) authorizing BGE an annualized gas base rate increase of $19.3 million, including $2.4 million to recover higher depreciation expense. The increase is equivalent to approximately 3.7% of total 1996 gas revenues. In granting the increase, the Commission provided a return on BGE's higher level of gas rate base associated with system expansion and improvement and recognized increases in gas operating expenses associated with maintaining the expanded gas distribution system. This was partially offset by a reduction in the authorized gas rate of return to 9.04% from the 9.40% gas rate of return previously authorized. The 1995 Rate Order also provided for the recognition of the remaining portion of postretirement benefits costs not currently included in gas rates and authorized the Company, effective January 1, 1998, to begin amortizing over a fifteen-year period the gas portion of postretirement and postemployment benefit costs deferred prior to December 1995. In addition, the Maryland Commission authorized the Company to amortize certain environmental costs incurred through October 1995 over a ten-year period and to defer for future recovery additional environmental costs incurred after that date. FRANCHISES BGE has nonexclusive electric and gas franchises to use streets and other highways which are adequate and sufficient to permit BGE to engage in its present business. All such franchises, other than the gas franchises in Manchester, Hampstead, Perryville, Sykesville, Havre de Grace, Mt. Airy, and Montgomery and Frederick Counties, are unlimited as to time. The gas franchises for these jurisdictions expire at various times from 2015 to 2087, except for Havre de Grace which has the right, exercisable at twenty-year intervals from 1907, to purchase all of BGE's gas properties in that municipality. Conditions of the franchises are satisfactory. BGE also has rights-of-way to maintain 26-inch natural gas mains across certain Baltimore City owned property (principally parks) which expire in 1998 and 2004, each subject to renewal during the last year thereof for an additional period of 25 years on a fair revaluation of the rights so granted. Conditions of the grants are satisfactory. Franchise provisions relating to rates have been superseded by the Public Service Commission Law of Maryland. DIVERSIFIED BUSINESSES The Company is engaged in diversified businesses through three groups of subsidiaries. BGE CORP. AND SUBSIDIARIES -- OUR ENERGY MARKETING COMPANIES INCLUDING OUR NEW POWER MARKETING BUSINESS BGE Corp. is a wholly owned subsidiary of BGE that serves as the holding company for our three energy marketing businesses: (Bullet) Power Marketing -- We recently formed a new subsidiary, CONSTELLATION POWER SOURCE, INC., for the purpose of entering the power marketing business. This new business involves the purchase and sale of electric power and electric power derivatives, and related activities including power brokering, marketing, risk management activities, and derivative trading. Goldman Sachs Power, LLC, an affiliate of Goldman Sachs & Co., the investment banking firm, is the exclusive advisor to Constellation Power Source, Inc. for risk management and power marketing. 13 (Bullet) Natural Gas Brokering -- During 1996 we expanded the activities of CONSTELLATION ENERGY SOURCE, INC. (formerly named BNG, Inc.). This subsidiary provides natural gas brokering and related services for wholesale and retail customers. (Bullet) Energy Services -- In 1995, we created BGE ENERGY PROJECTS & SERVICES, INC., which provides energy services including private electric and gas distribution systems, energy consulting, power quality, and campus energy systems. We provide district cooling and heating systems through that subsidiary and through our partnership with the Poole & Kent Company, called COMFORTLINKTM. We also sell power quality equipment through another subsidiary, POWERDIGM SYSTEMS, INC.; and perform energy services contracting work though a subsidiary SKILES ENERGY CORP. THE CONSTELLATION COMPANIES -- POWER GENERATION, REAL ESTATE, AND FINANCIAL INVESTMENTS The Constellation Companies' businesses are concentrated in three major areas -- power generation projects, financial investments, and real estate projects (including senior-living facilities). A significant portion of the Constellation Companies' activities are conducted through joint ventures in which they hold varying ownership interests. The Constellation Companies hold up to a 50% ownership interest in 26 power generating projects in operation or under construction and indirect ownership of minority interests in several power generation and distribution projects accounting for $373 million of the Constellation Companies' assets. These projects, all of which either are qualifying facilities under the Public Utility Regulatory Policies Act of 1978 or are otherwise exempt from the Public Utility Holding Company Act of 1935, are of the following types and aggregate generation capacities: coal 160 MW, solar 170 MW, geothermal 126 MW, waste coal 182 MW, wood burning 70 MW, hydro 30 MW, and natural gas 182 MW. In addition, another $4 million has been spent on projects in development. The Constellation Companies also participate in the operation and maintenance of 15 power generation projects existing or under construction, 12 of which are projects in which the Constellation Companies hold an ownership interest. Financial investments account for $204 million of the Constellation Companies' assets. These assets include $94 million in internally and externally managed securities portfolios, $77 million in a monoline financial guaranty (credit enhancement) company, and $33 million in tax-oriented transactions. Real estate and senior-living projects account for $562 million of the Constellation Companies' assets. These projects include raw land, office buildings, retail projects, distribution facility projects, an entertainment, dining, and retail complex in Orlando, Florida (which we may sell as discussed below), a mixed-use planned-unit development, and senior-living facilities. The majority of the real estate projects are in the Baltimore-Washington area and have been adversely affected by the depressed real estate and economic market. The Constellation Companies' investment in wholesale power generating projects includes $227 million representing ownership interests in 16 projects that sell electricity in California under Interim Standard Offer No. 4 (SO4) 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 thereafter at fixed capacity payments plus variable energy rates based on the utilities' avoided cost for the remaining term of the agreements. Avoided cost generally represents a utility's lowest-cost next-available source of generation to service the demands on its system. These power generation projects began the conversion to supplying electricity at avoided cost rates in 1996 and will continue to convert 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. At current avoided cost levels, the Constellation Companies would experience reduced earnings or incur losses associated with these projects, which could be significant. While eight projects transition from fixed to variable energy rates in 1997 and 1998, revenues from the other projects having SO4 contracts are expected to continue to increase during this period tending to offset revenue declines on those projects. Six of the seven largest revenue producing projects will not make the transition to variable energy rates until the 1999-2000 timeframe such that any material reductions in revenues would not be anticipated before 2000. During the second quarter of 1996, the Constellation Companies determined that successful mitigation measures for two of these plants are now unlikely and that the investment in these plants was impaired. Accordingly, the Constellation Companies recorded a $7.0 million after-tax write off of the investment in these plants. 14 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, changing fuels to reduce operating costs, renegotiating the power purchase agreements to improve the terms, restructuring financings to improve the financing terms, and selling its ownership interests in the projects. The Company cannot predict the financial impact that these matters regarding any of these projects may have on the Constellation Companies or BGE, but the impact could be material. FIRST QUARTER EVENT WILL RESULT IN AN ESTIMATED $12 MILLION AFTER TAX WRITEDOWN AT THE CONSTELLATION COMPANIES In ITEM 7. MD&A -- CONSTELLATION COMPANIES' OPERATIONS AND NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS, we discuss the real estate market and financial matters about the Constellation Companies' real estate projects including: (Bullet) our current real estate strategy is to hold each real estate project until we can realize a reasonable value for it, (Bullet) depending on market conditions, we could have losses on future sales, (Bullet) accounting rules require a writedown to market value if either of two things occurs: -- we change our intent to hold a project to an intent to sell, or -- expected cash flow from a project is less than the investment in the project. In mid-March we received an unsolicited offer to buy the Constellation Companies' Church Street Station, which is an entertainment, dining, and retail complex in Orlando, Florida. Because of the unique character of Church Street Station and the geographic distance of this project from our other real estate holdings in the Baltimore-Washington corridor, we decided that considering a sale is the appropriate strategy. We plan to negotiate with this potential purchaser and also to explore whether there are others who are interested in purchasing the project on better terms. Based on the accounting rules mentioned above, our decision is a change of intent, and we are required to write down our investment to the market value. Determining the market value for such a unique project is difficult, but the unsolicited offer is the best indication available to us and we used it to determine the amount of the writedown. Although all financial data for the first quarter is not yet available, this means we expect the Constellation Companies' earnings for the first quarter of 1997 to be generally flat compared to 1996 in spite of this writedown. BGE HOME PRODUCTS & SERVICES, INC. AND ITS SUBSIDIARY -- OUR HOME PRODUCTS AND COMMERCIAL BUILDING SYSTEMS BUSINESSES For many years, BGE sold and serviced appliances and provided home improvements. In 1994, BGE moved this business into a subsidiary, BGE Home Products & Services, Inc. This company sells and services appliances, including televisions, stereo and sound equipment, video cassette recorders, videocameras, washers, dryers, ranges, refrigerators, microwaves, and other appliances primarily used by customers at home. It has an active home improvement business including kitchen and bathroom remodeling, replacement doors and windows, siding, and roofing. Its subsidiary, Maryland Environmental Systems, Inc. specializes in the installation and service of commercial and residential heating, air conditioning, plumbing, and electrical systems. 15 DIVERSIFIED BUSINESS CAPITAL REQUIREMENTS Capital requirements for diversified businesses for 1994 through 1996, along with estimated amounts for 1997 through 1999, are set forth below:
1994 1995 1996 1997 1998 1999 ---- ---- ---- ---- ---- ---- (IN MILLIONS) Diversified Business Capital Requirements - ----------------------------------------- Investment requirements................................ $51 $118 $118 $214 $180 $205 Retirement of long-term debt........................... 37 55 52 108 165 186 --- ---- ---- ---- ---- ---- Total diversified business capital requirements...... $88 $173 $170 $322 $345 $391 === ==== ==== ==== ==== ====
In the past, capital requirements of our diversified businesses only included the Constellation Companies because they had the only significant capital requirements. However, we anticipate Constellation Power Source, Inc. will have significant capital requirements and these are included in the table for future years. As discussed below under "Investment Requirements," capital requirements for ComfortLink are also included this year. Our diversified businesses expect to expand their businesses. This may include expansion in the energy marketing, power generation, financial investments, real estate, and senior-living facility businesses. Such expansion could mean more investments in and acquisition of new projects. Our diversified businesses have met their capital requirements in the past through borrowing, cash from their operations, and from time to time, loans or equity contributions from BGE. Our diversified businesses plan to raise the cash needed to meet capital requirements in the future through these same methods. DIVERSIFIED BUSINESS INVESTMENT REQUIREMENTS The investment requirements shown above include the Constellation Companies' investments in financial limited partnerships and funding for the development and acquisition of projects, as well as net loans made to project partnerships, ComfortLink's funding for construction of district energy projects, and funding for growing Constellation Power Source's power marketing business. Investment requirements for the years 1997 through 1999 reflect estimates of funding during such periods for ongoing and anticipated projects. Also, guarantees of $47 million may be called which are not included above. Estimates of our diversified businesses' investment requirements are subject to continuous review and modification. Actual investment requirements may vary significantly from the amounts above due to the type and number of projects selected for development, the impact of market conditions on those projects, the ability to obtain financing, and the availability of internally generated cash. DIVERSIFIED BUSINESS DEBT AND LIQUIDITY Our diversified businesses plan to meet capital requirements by refinancing debt as it comes due, by additional borrowing, and with cash generated by the businesses. This includes cash from operations, sale of assets, and earned tax benefits. BGE Home Products & Services may also meet capital requirements through sales of receivables as discussed in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS. If the Constellation Companies can get a reasonable value for real estate, additional cash may be obtained by selling real estate projects. The Constellation Companies' ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. In addition, the Constellation Companies have a $75 million revolving credit agreement and ComfortLink has a $50 million revolving credit agreement to provide additional cash for short-term financial needs. See NOTES 3 and 4 TO CONSOLIDATED FINANCIAL STATEMENTS AND ITEM 7. MD&A -- LIQUIDITY AND CAPITAL RESOURCES -- CAPITAL REQUIREMENTS OF OUR DIVERSIFIED BUSINESSES for additional information about diversified businesses. 16 ENVIRONMENTAL MATTERS The Company is subject to regulation with regard to air and water quality, waste disposal, and other environmental matters by various federal, state, and local authorities. Certain of these regulations require substantial expenditures for additions to utility plant and the use of more expensive low-sulfur fuels. While the Company cannot now precisely estimate the total effect of existing and future environmental regulations and standards upon its existing and proposed facilities and operations, the necessity for compliance with existing standards and regulations has caused BGE to increase capital expenditures by approximately $138 million during the five-year period 1992-1996. It is estimated that the capital expenditures necessary to comply with such standards and regulations will be approximately $16 million, $38 million, and $14 million for 1997, 1998, and 1999, respectively. AIR: The Federal Clean Air Act (the Act) mandates health and welfare standards for concentrations of air pollutants. The State of Maryland is charged by the Act with the responsibility for setting limits on all major sources of these pollutants in the State so that these standards are not exceeded. Except for Crane Units 1 and 2, BGE's generating units are limited to burning fuel (coal or oil) with sulfur content of 1% or below. All units are limited to emitting particulate matter at or below 0.02 grains per standard cubic foot of exhaust gas for oil fired units and 0.03 grains per standard cubic foot for coal-fired units. Brandon Shores, a newer plant, is subject to more stringent standards for sulfur dioxide (1.2 pounds per million Btu), and nitrogen dioxide (0.7 pounds per million Btu). The Crane Units must meet limits of 3.5 pounds per million Btu for sulfur dioxide, which is equivalent to a coal sulfur content of approximately 2.4%. BGE is in compliance with existing air quality regulations. The Clean Air Act Amendments of 1990 contain 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 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 through fuel switching and unit retirements. BGE is currently examining what actions will be required in order to comply with Phase II. 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 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 $90 million. BGE is currently unable to predict the cost of compliance with the additional requirements at other BGE facilities. WATER: The discharge of effluents into the waters of the State of Maryland is regulated by the Maryland Department of the Environment (MDE), in accordance with the National Pollutant Discharge Elimination System (NPDES) permit program, established pursuant to the Federal Clean Water Act. At the present time, all of BGE's steam electric generating plants have the required NPDES permits. MDE water quality regulations require, among other things, specifying procedures for determining compliance with State water quality standards. These procedures require extensive studies involving sampling and monitoring of the waters around affected generating plants. The State of Maryland may require changes in plant operations. At this time BGE continually performs studies to determine whether any modifications will be required to comply with these regulations. WASTE DISPOSAL: The United States Environmental Protection Agency (EPA) has promulgated regulations implementing those portions of the Resource Conservation and Recovery Act which deal with management of hazardous wastes. These regulations, and the Hazardous and Solid Waste Amendments of 1984, designate certain spent materials as hazardous wastes and establish standards and permit requirements for those who generate, transport, store, or dispose of such wastes. The State of Maryland has adopted similar regulations governing the management of hazardous wastes, which closely parallel the federal regulations. BGE has implemented procedures for compliance with all applicable federal and state regulations governing the management of hazardous wastes. Certain high volume utility wastes such as fly ash and bottom ash have been exempted from these regulations. The Company currently utilizes almost all of its coal fly ash and bottom 17 ash as structural fill material in a manner approved by the State of Maryland. The remainder of the coal ash is sold to the construction industry for a number of approved applications. The Federal Comprehensive Environmental Response, Compensation and Liability Act (Superfund statute) establishes liability for the cleanup of hazardous wastes found contaminating the soil, water, or air. Those who generated, transported or deposited the waste at the contaminated site are each jointly and severally liable for the cost of the cleanup, as are the current property owner and their predecessors in title at the time of the contamination. In addition, many states have enacted laws similar to the Superfund statute. On October 16, 1989, the EPA filed a complaint in the U.S. District Court for the District of Maryland under the Superfund statute against BGE and seven other defendants to recover past and future expenditures associated with cleanup of a site located at Kane and Lombard Streets in Baltimore. The EPA complaint was dismissed in November 1995. The State of Maryland intervened by filing a similar complaint in the same case and court on February 12, 1990. The complaints allege that BGE arranged for its fly ash to be deposited on the site. Settlement discussions continue among all parties. Additional investigation was initiated on the remainder of the site by the MDE for the EPA but was never completed. BGE and three other defendants agreed to complete the remedial investigation and feasibility study of groundwater contamination around the site in a July 1993 consent order. The remedial action, if any, for the remainder of the site will not be selected until these investigations are concluded. Therefore, neither the total site cleanup costs, nor BGE's share, can presently be estimated. In the early 1970's, BGE shipped an unknown number of scrapped transformers to Metal Bank of America, a metal reclaimer in Philadelphia. Metal Bank's scrap and storage yard has been found to be contaminated with oil containing high levels of PCBs (PCBs are hazardous chemicals frequently used as a fire-resistant coolant in electrical equipment). On December 7, 1987, the EPA notified BGE and nine other utilities that they are considered potentially responsible parties (PRPs) with respect to the cleanup of the site. A remedial investigation and feasibility study (RI/FS) by BGE and the other PRPs was submitted to the EPA on October 14, 1994. Estimated costs for the various remedies included in the RI/FS range greatly (from $15 million to $45 million). Until a specific remedy is chosen, BGE is not able to predict the actual cleanup costs. BGE's share of the cleanup costs, estimated to be approximately 15.79%, could be material. From 1985 until 1989, BGE shipped waste oil and other materials to the Industrial Solvents and Chemical Company in York County, Pennsylvania for disposal. The Pennsylvania Department of Environmental Resources (Pennsylvania Department) subsequently investigated this site and found it to be heavily contaminated by hazardous wastes. The Pennsylvania Department notified BGE on August 15, 1990, that it and approximately 1,000 other entities were PRPs with respect to the cost of all remedial activities to be conducted at the site. The PRPs have agreed to perform waste characterization, remove and dispose of all tanks and drums of waste, and perform a remedial investigation at the site. BGE's share of the liability at this site currently is estimated to be approximately 2.39%, but this may change as additional information about the site is obtained. The actual cost of remedial activities has not been determined. As a result of these factors, BGE's potential liability cannot presently be estimated. However, such liability is not expected to be material. On August 30, 1994, BGE was named as a defendant in UNITED STATES V. KEYSTONE SANITATION COMPANY, ET AL. The litigation was instituted by EPA in the United States District Court for the Middle District of Pennsylvania involving contamination of the Keystone Sanitation Company landfill Superfund site located in Adams County, Pennsylvania. BGE was named as a third party defendant based upon allegations that BGE had drums of asbestos shipped to the site. There are eleven original defendants, approximately 150 other third party defendants, and approximately 570 fourth party defendants. Neither the costs of future site remediation, nor the extent of BGE's potential liability can be estimated at this time. However, such liability is not expected to be material. In December 1995, BGE was notified by the EPA that it is one of approximately 650 parties that may have incurred liability under the Superfund statute for shipments of hazardous wastes to a site in Denver, Colorado known as the RAMP Industries site. BGE, through its disposal vendor, shipped a small amount of low level radioactive waste to the site between 1989 and 1992. The site, which was found to have been operated improperly, was closed in 1994. That same year, the EPA began a clean up of the site which will consist of removal of drums of radioactive and hazardous mixed wastes. To date the EPA has processed approximately one third of the drums and incurred expenses of about $2.2 million. After the EPA completes its drum removal phase of the clean up it will investigate potential soil and groundwater contamination. 18 Although BGE's potential liability cannot be estimated, it is believed that such liability is not likely to be substantial based on the limited amount of waste shipped to the site from BGE facilities. In September, 1996, BGE received an information request from the EPA concerning the Drumco Drum Dump Site, located in the Curtis Bay area of Maryland. This site was the subject of an emergency drum removal action in 1991, due to a concern about hazardous substances leaking from drums and posing a threat to human health and the environment. According to EPA documents, approximately $2 million dollars was spent on the drum removal action. To our knowledge, no long-term remediation is planned for this site. In addition, we understand that EPA has sent information requests to approximately 17 other parties. BGE's records indicate that it sold empty drums to Drumco, Inc. from approximately 1983-1990. BGE is currently reviewing all relevant documents and interviewing employees involved in selling the drums to Drumco. BGE's potential liability cannot be estimated at this time. However we believe that any liability is not likely to be material based on BGE's records showing that only empty storage drums were sold to Drumco, Inc. In the early part of the century, predecessor gas companies (which were later merged into BGE) manufactured coal gas for residential and industrial use. The residue from this manufacturing process was coal tar, previously thought to be harmless but now found to contain a number of chemicals designated by the EPA as hazardous substances. BGE is coordinating an investigation of these former coal gas plant sites, including exploration of corrective action options to remove coal tar, with the MDE. In late December 1996, the Maryland Department of the Environment and BGE signed a consent order that requires BGE to implement remedial action plans addressing contamination at and related to the Spring Gardens site. The specific remedial actions for this site will be developed in the future. As explained in NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS, BGE has recognized estimated environmental costs at all former gas manufacturing plant sites (based on remedial action options) which are considered probable totaling $50 million in nominal dollars. These costs, net of accumulated amortization, have been deferred as a regulatory asset (see NOTE 5 TO CONSOLIDATED FINANCIAL STATEMENTS). Accounting rules also require BGE to disclose additional costs deemed by BGE to be less likely than probable costs, but still "reasonably possible" of being incurred at these sites. Because of the results of recent studies at these sites, it is reasonably possible that these additional costs could exceed the amount recognized by approximately $48 million in nominal dollars ($11 million in current dollars, plus the impact of inflation at 3.1% over a period of up to 60 years). As previously disclosed, on May 3, 1994 Constellation Power, Inc. (formerly "Constellation Energy, Inc.") (CPI) was named as a defendant in REPUBLIC IMPERIAL ACQUISITION V. STOCKMAR ENERGY, INC., ET AL. Civil No. 940120R(LSP) (Dist. Ct., So. Dist. California), litigation concerning a waste landfill. In December 1996, CPI was dismissed from this proceeding. EMPLOYEES As of December 31, 1996, BGE employed 7,032 people. 19 ITEM 2. PROPERTIES ELECTRIC: The principal electric generating plants of BGE are as follows:
GENERATION INSTALLED ---------- PLANT LOCATION CAPACITY (MW) PRIMARY FUEL 1996 1995 ----- -------- ------------- ------------ ---- ---- (AT DECEMBER 31, 1996) Steam Calvert Cliffs Calvert County, MD 1,675 Nuclear 12,069,937 12,937,965 Brandon Shores Anne Arundel County, MD 1,291 Coal 8,849,357 9,091,443 Herbert A. Wagner Anne Arundel County, MD 1,006 Coal/Oil/Gas 3,149,334 3,002,183 Charles P. Crane Baltimore County, MD 380 Coal 2,000,992 1,631,798 Gould Street Baltimore City, MD 104 Oil 49,583 66,851 Riverside Baltimore County, MD 78 Oil/Gas 15,356 40,229 Jointly Owned -- Steam Keystone Armstrong and 359(A) Coal 2,650,786 2,429,568 Indiana Counties, PA Conemaugh Indiana County, PA 181(A) Coal 1,202,914 1,244,060 Combustion Turbine Notch Cliff Baltimore County, MD 128 Gas 12,470 27,702 Perryman Harford County, MD 350 Oil/Gas 91,197 42,875 Westport Baltimore City, MD 121 Gas 6,420 19,133 Riverside Baltimore County, MD 173 Oil/Gas 5,450 7,118 Philadelphia Road Baltimore City, MD 64 Oil 1,829 4,813 Charles P. Crane Baltimore County, MD 14 Oil 707 1,237 Herbert A. Wagner Anne Arundel County, MD 14 Oil 513 971 ----- ---------- ---------- Totals 5,938 30,106,845 30,547,946 ===== ========== ==========
(A) BGE-owned proportionate interest and entitlement. These totals include diesel capacity of 2 megawatts and 1 megawatt for Keystone and Conemaugh, respectively. BGE also owns two-thirds of the outstanding capital stock of Safe Harbor Water Power Corporation, and is currently entitled to 277 megawatts of the rated capacity of the Safe Harbor Hydroelectric Project. Safe Harbor is operated under a FERC license which expires in the year 2030. GAS: BGE has propane air and liquefied natural gas facilities as described in GAS OPERATIONS. 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 and service. 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 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. 20 ITEM 3. LEGAL PROCEEDINGS ASBESTOS Since 1993, BGE has been 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. Approximately 520 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 made by one manufacturer -- Pittsburgh Corning Corp. -- against BGE and approximately eight others, as third-party defendants. These claims 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 manufacturer, 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 -- ELECTRIC RATE MATTERS, NUCLEAR OPERATIONS, ENVIRONMENTAL MATTERS, and NOTE 12 TO CONSOLIDATED FINANCIAL STATEMENTS for other information about legal or regulatory proceedings involving BGE. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not Applicable. 21 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS STOCK TRADING BGE's Common Stock is traded under the ticker symbol BGE. It is listed on the New York, Chicago, and Pacific stock exchanges. It has unlisted trading privileges on the Boston, Cincinnati, and Philadelphia exchanges. As of February 28, 1997, there were 76,929 common shareholders of record. DIVIDEND POLICY We pay dividends on our Common Stock when our Board of Directors declares them. There is no limitation on our paying Common Stock dividends, other than we must first pay all dividends (and any redemption payments) due on our preference stock. 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 1996 and 1995 in the amounts set forth below. COMMON STOCK DIVIDENDS AND PRICE RANGES
1996 1995 ----------------------------- ---------------------------- PRICE* PRICE* DIVIDEND ------------- DIVIDEND ---------------- DECLARED HIGH LOW DECLARED HIGH LOW -------- ---- --- -------- ---- --- First Quarter......................................... $ .39 $ 29-1/2 $ 26-1/8 $ .38 $ 25 $ 22 Second Quarter........................................ .40 28-5/8 25-1/2 .39 26-1/2 23-1/8 Third Quarter......................................... .40 28-5/8 25 .39 26-5/8 24-3/8 Fourth Quarter........................................ .40 28-3/4 25-3/4 .39 29 25-1/2 ------ ----- Total............................................... $ 1.59 $1.55 ====== =====
*Based on New York Stock Exchange Composite Transactions as reported in the eastern edition of THE WALL STREET JOURNAL. 22 Item 6. Selected Financial Data
Compound 1996 1995 1994 1993 1992 Growth - ----------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in thousands, except per share amounts) 5-Year 10-Year Summary of Operations Total Revenues $3,153,247 $2,934,799 $2,782,985 $2,741,385 $2,559,536 4.63% 4.63% Expenses Other Than Interest and Income Taxes 2,483,782 2,239,107 2,147,726 2,124,993 2,024,227 4.15 5.21 ------------------------------------------------------------- Income From Operations 669,465 695,692 635,259 616,392 535,309 6.54 2.73 Other Income 6,130 8,819 32,365 20,310 22,132 (26.25) (9.83) ------------------------------------------------------------- Income Before Interest and Income Taxes 675,595 704,511 667,624 636,702 557,441 5.55 2.49 Net Interest Expense 198,438 196,977 190,154 188,764 189,747 0.19 5.82 ------------------------------------------------------------- Income Before Income Taxes 477,157 507,534 477,470 447,938 367,694 8.37 1.39 Income Taxes 166,333 169,527 153,853 138,072 103,347 14.22 1.65 ------------------------------------------------------------- Net Income 310,824 338,007 323,617 309,866 264,347 4.17 1.25 Preferred and Preference Stock Dividends 38,536 40,578 39,922 41,839 42,247 (2.05) 3.67 ------------------------------------------------------------- Earnings Applicable to Common Stock $ 272,288 $ 297,429 $ 283,695 $ 268,027 $ 222,100 5.26 0.95 ============================================================= Earnings Per Share of Common Stock $1.85 $2.02 $1.93 $1.85 $1.63 2.07 (1.26) Dividends Declared Per Share of Common Stock $1.59 $1.55 $1.51 $1.47 $1.43 2.58 3.03 Ratio of Earnings to Fixed Charges 3.10 3.21 3.14 3.00 2.65 6.43 (2.97) Ratio of Earnings to Fixed Charges and Preferred and Preference Stock Dividends Combined 2.44 2.52 2.47 2.34 2.08 6.04 (2.68) Financial Statistics at Year End Total Assets $8,550,970 $8,316,663 $8,037,502 $7,829,613 $7,208,660 3.68 6.44 ============================================================= Capitalization Long-term debt $2,758,769 $2,598,254 $2,584,932 $2,823,144 $2,376,950 2.91 5.62 Preferred stock -- 59,185 59,185 59,185 59,185 -- -- Redeemable preference stock 134,500 242,000 279,500 342,500 395,500 (19.53) 10.40 Preference stock not subject to mandatory redemption 210,000 210,000 150,000 150,000 110,000 13.81 6.68 Common shareholders' equity 2,857,113 2,812,682 2,717,866 2,620,511 2,534,639 5.82 5.77 ------------------------------------------------------------- Total Capitalization $5,960,382 $5,922,121 $5,791,483 $5,995,340 $5,476,274 3.12 5.63 ============================================================= Book Value Per Share of Common Stock $19.35 $19.07 $18.42 $17.94 $17.63 2.62 3.43 Number of Common Shareholders 77,550 79,811 81,505 82,287 80,371 1.74 0.07
Baltimore Gas and Electric Company and Subsidiaries 23 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Introduction In Management's Discussion and Analysis we explain the general financial condition and the results of operations for BGE and its diversified business subsidiaries including: (bullet) what factors affect our business, (bullet) what our earnings and costs were in 1996 and 1995, (bullet) why those earnings and costs were different from the year before, (bullet) where our earnings came from, (bullet) how all of this affects our overall financial condition, (bullet) what our expenditures for capital projects were in 1994 through 1996 and what we expect them to be in 1997 through 1999, and (bullet) where cash will come from to pay for future capital expenditures. As you read Management's Discussion and Analysis, it may be helpful to refer to our Consolidated Statements of Income on page 35, which present the results of our operations for 1996, 1995, and 1994. In Management's Discussion and Analysis, we analyze and explain the annual changes in the specific line items in the Consolidated Statements of Income. Our analysis may be important to you in making decisions about your investments in BGE. You may notice some changes in this year's discussion, compared to past years. This is because we volunteered to participate in a pilot program with the Securities and Exchange Commission to write financial documents in plain English. As a result, we have re-written our entire Management's Discussion and Analysis section. Our goal is to discuss our financial condition in language that is more easily understood. BGE and Potomac Electric Power Company have agreed to merge into a new company named Constellation Energy Corporation. We plan to complete the merger as soon as we obtain all regulatory approvals. These matters are discussed in more detail in Note 12 beginning on page 52 and in a Registration Statement on Form S-4 (Registration No. 33-64799). The merger may impact many of the matters discussed in Management's Discussion and Analysis including earnings, results of electric operations, expenses, liquidity, and capital resources. The electric utility industry is undergoing rapid and substantial change. Competition is increasing. The regulatory environment (federal and state) is shifting. These matters are discussed briefly in the "Competition and Response to Regulatory Change" section on page 26 in Management's Discussion and Analysis. They are discussed in detail in this Annual Report on Form 10-K. BGE continuously evaluates these changes. Based on the evaluations, BGE refines short and long term business plans with the primary goal of protecting our security holders' investments and providing them with superior returns on their investment in BGE. In order to support this primary goal, we also focus on other groups who impact our primary goal. For example, we stress providing low cost, reliable power to our electric customers. As you read Management's Discussion and Analysis, many BGE initiatives to support our primary goal are mentioned. These include the proposed merger with Potomac Electric Power Company, designed to position us to remain competitive as the industry changes, and our diversification effort. We enter new businesses which we believe will support our primary goal. For example, new businesses may be opportunities to: (bullet) provide customers of our core energy business additional services, or (bullet) attract new customers for our core energy business, or (bullet) expand our diversified stream of revenues. We believe our newest subsidiary, Constellation Power Source, Inc., will satisfy all three criteria. Its proposed power marketing business is described in detail in the front of this report. - -------------------------------------------------------------------------------- Results of Operations In this section, we discuss our 1996 and 1995 earnings and the factors affecting them. We begin with a general overview, then separately discuss earnings for the utility business and for diversified businesses. Overview Total Earnings per Share of Common Stock 1996 1995 1994 - -------------------------------------------------------------------------------- Earnings per share from current-year operations: Utility business $1.96 $1.84 $1.81 Diversified businesses (subsidiaries) .31 .18 .12 ---------------------- Total earnings per share from current-year operations 2.27 2.02 1.93 Disallowed replacement energy costs (see Note 12) (.42) -- -- ---------------------- Total earnings per share $1.85 $2.02 $1.93 ====================== 1996 Our 1996 total earnings decreased $25.1 million, or $.17 per share, from 1995. Our total earnings decreased because we reserved for disallowed replacement energy costs. We discuss this in detail in the "Disallowed Replacement Energy Costs" section on page 27. In 1996, we had higher utility earnings from current-year operations due to three factors: we sold more electricity and gas due to colder winter weather (people use more gas and electricity to heat their homes in colder weather), there was an increase in the number of customers, and we had lower operations and maintenance expenses. We would have had even higher utility earnings from current-year operations except we sold less electricity in the third quarter due to milder summer weather. We discuss our utility earnings in more detail beginning on page 26. Baltimore Gas and Electric Company and Subsidiaries 24 In 1996, we had higher earnings from our diversified business subsidiaries mostly because the Constellation Companies had higher earnings from power generation projects and financial investments. We discuss our diversified business earnings in more detail beginning on page 30. 1995 Our 1995 total earnings increased $13.7 million, or $.09 per share, from 1994. In 1995, we had higher utility earnings mostly due to greater sales of electricity during an extremely hot summer and higher electricity and gas sales resulting from colder fall weather. We would have had even higher utility earnings except for the mild weather in the first half of the year, lower net other income and deductions (miscellaneous non-operating income and expenses), and lower allowance for funds used during construction (an accounting procedure used to exclude the cost of capital from expense and include it as part of the cost of utility plant construction). In 1995, we had higher earnings from our diversified businesses mostly because the Constellation Companies had higher earnings from power generation projects and financial investments. Utility Business Before we go into the details of our electric and gas operations, we believe it is important to discuss four factors that have a strong influence on our utility business performance: regulation, the weather, other factors including the condition of the economy in our service territory, and competition. Regulation by the Maryland Public Service Commission The Maryland Public Service Commission (Maryland Commission) determines the rates we can charge our customers. Our rates consist of a "base rate" and a "fuel rate". The base rate is the rate the Maryland Commission allows us to charge our customers for the cost of providing them service, plus a profit. We have both an electric base rate and a gas base rate. Higher electric base rates apply during the summer when the demand for electricity is the highest. Gas base rates are not affected by seasonal changes. The Maryland Commission allows us to include in base rates a component to recover money spent on conservation programs. This component is called an "energy conservation surcharge." However, under this surcharge the Maryland Commission limits what our profit can be. If, at the end of the year, we have exceeded our allowed profit, we lower the amount of future surcharges to our customers to correct the amount of overage, plus interest. In addition, we charge our electric customers separately for the fuel (nuclear fuel, coal, gas, or oil) we use to generate electricity. The actual cost of the fuel is passed on to the customer with no profit. We also charge our gas customers separately for the natural gas they consume. The price we charge for the natural gas is based on a Market Based Rates incentive mechanism approved by the Maryland Commission. We discuss Market Based Rates in more detail in the "Gas Cost Adjustments" section on page 28 and in Note 1 on page 43. From time to time, when necessary to cover increased costs, we ask the Maryland Commission for base rate increases. Not every request for base rate increases is granted in full. However, the Maryland Commission has historically allowed BGE to increase base rates to recover costs for replacing utility plant assets, plus a profit, beginning at the time of replacement. Generally, rate increases improve our utility earnings because they allow us to collect more revenue. However, rate increases are normally granted based on historical data and those increases may not always keep pace with increasing costs. Weather Weather affects the demand for electricity and gas, especially among our residential customers. Very hot summers and very cold winters increase demand. Mild weather reduces demand. We measure the weather's effect using "degree days." A degree day is the difference between the average daily actual temperature and a baseline temperature of 65 degrees. Cooling degree days result when the daily actual temperature exceeds the 65 degree baseline. Heating degree days result when the daily actual temperature is less than the baseline. During the cooling season, hotter weather is measured by more cooling degree days and results in greater demand for electricity to operate cooling systems. During the heating season, colder weather is measured by more heating degree days and results in greater demand for electricity and gas to operate heating systems. The following chart shows the number of cooling and heating degree days in 1996 and 1995, shows the percentage changes in the number of degree days from prior years, and shows the number of degree days in a "normal" year as represented by the 30-year average. 30-Year 1996 1995 Average - -------------------------------------------------------------------------------- Cooling degree days 786 1,056 804 Percentage change compared to prior year (25.6)% 11.3% Heating degree days 5,138 4,601 4,901 Percentage change compared to prior year 11.7% (1.5)% Other Factors Other factors, aside from weather, impact the demand for electricity and gas. These factors include the "number of customers" and "usage per customer" during a given period. The number of customers in a given period is affected by new home and apartment construction and by the number of businesses in our service territory. Usage per customer refers to all other items impacting customer sales which cannot be separately measured. These factors include the strength of the economy in our service territory. When the economy is healthy and expanding, customers tend to consume more electricity and gas. Conversely, during an economic downtrend, our customers tend to consume less electricity and gas. We use these terms later in our discussions of electric and gas operations. In those sections, we discuss how these and other factors affected electric and gas sales during 1996 and 1995. Baltimore Gas and Electric Company and Subsidiaries 25 Competition and Response to Regulatory Change Our business is also affected by competition. Electric utilities are facing competition on three fronts: (bullet) in the construction of generating units to meet increased demand for electricity, (bullet) in the sale of their electricity in the bulk power markets, and (bullet) in the future, for electric sales to retail customers which utilities now serve exclusively. We regularly reevaluate our strategies with two goals in mind: to improve our competitive position, and to anticipate and adapt to regulatory changes. In September 1995, we decided that a merger with Potomac Electric Power Company would help us compete by maintaining low-cost production and increasing our size. The pending merger is more thoroughly discussed in Note 12 on page 52. Although we believe the merger will improve our competitive position in the future, no one can predict the ultimate effect competition or regulatory change will have on our earnings or on the earnings of the merged company. We will continue to develop strategies to keep us competitive. These strategies might include one or more of the following: (bullet) the complete or partial separation of our generation, transmission, and distribution functions (bullet) other internal restructuring (bullet) mergers or acquisitions of utility or non-utility businesses (bullet) addition or disposition of portions of our service territories (bullet) spin-off or distribution of one or more businesses We cannot predict whether any transactions of the types described above may actually occur, nor can we predict what their effect on our financial condition or competitive position might be. We discuss competition in our electric and gas businesses in more detail in this Annual Report on Form 10-K under the headings "Electric Regulatory Matters and Competition" and "Gas Regulatory Matters and Competition." Utility Business Earnings per Share of Common Stock 1996 1995 1994 - -------------------------------------------------------------------------------- Utility earnings per share from current-year operations: Electric business $1.75 $1.70 $1.71 Gas business .21 .14 .10 ------------------------- Total utility earnings per share from current-year operations 1.96 1.84 1.81 Disallowed replacement energy costs (see Note 12) (.42) -- -- ------------------------- Total utility earnings per share $1.54 $1.84 $1.81 ========================= Our 1996 total utility earnings decreased $44.5 million, or $.30 per share, from 1995. Our 1995 utility earnings increased $5.6 million, or $.03 per share, from 1994. We discuss the factors affecting utility earnings below. Electric Operations Electric Revenues The changes in electric revenues in 1996 and 1995 compared to the respective prior year were caused by: 1996 1995 - -------------------------------------------------------------------------------- (In millions) Electric system sales volumes $ 0.4 $ 43.4 Base rates (2.5) 23.2 Fuel rates (12.3) (13.8) ---------------------- Total change in electric revenues from electric system sales (14.4) 52.8 Interchange and other sales (11.1) 49.0 Other 4.5 1.4 ---------------------- Total change in electric revenues $(21.0) $103.2 ====================== Electric System Sales Volumes "Electric system sales" are sales to customers in our service territory at rates set by the Maryland Commission. These sales do not include interchange sales and sales to others. The percentage changes in our electric system sales volumes, by type of customer, in 1996 and 1995 compared to the respective prior year were: 1996 1995 - -------------------------------------------------------------------------------- Residential 2.5% 2.8% Commercial (0.3) 2.3 Industrial 0.1 3.6 In 1996, we sold more electricity to residential customers for three reasons: colder weather in the first quarter, greater electricity usage per customer, and an increase in the number of customers. We would have sold even more electricity to residential customers except for milder summer weather. We sold about the same amount of electricity to commercial and industrial customers as we did in 1995. As mentioned above, weather impacts residential, more than commercial and industrial, sales. In 1996 other items offset the impact of weather on commercial and industrial sales. Other items include the demand for power to fuel manufacturing equipment and office machinery, which vary with changes in the customers' businesses. For example, if a manufacturing plant has a slow year, it will make less product and use less power to run its assembly lines. In 1995, we sold more electricity to residential and commercial customers mostly because we had an increase in the number of customers and we had extremely hot summer weather and cold fall weather. We would have sold even more electricity to those customers except we had milder weather in the first half of 1995 compared to 1994. We sold more electricity to industrial customers mostly because we had an increase in the number of customers and more demand for electricity from Bethlehem Steel (our largest customer). Base Rates In 1996, base rate revenues were about the same as they were in 1995. Although we sold more electricity this year, our revenues did not increase because the higher sales occurred during the winter when our base rates are lower. Baltimore Gas and Electric Company and Subsidiaries 26 In 1995, base rate revenues were higher than in 1994 because of a higher energy conservation surcharge and also because we did not have to reduce conservation revenues as we did in 1994, when we exceeded our allowed profit. From July 1, 1993, through June 30, 1994, we exceeded our profit limit under the energy conservation surcharge. To correct the overage, we lowered the surcharge on our customers' bills from December 1993 to November 1994. As a result, we billed $20.1 million less than we would have otherwise. We also exceeded the limit on our profit during 1996. Therefore, we excluded $28.5 million of our 1996 surcharge billings from revenue, and we will lower the surcharge on our customers' bills beginning in July 1997 to correct the overage. Fuel Rates The fuel rate is the rate the Maryland Commission allows us to charge our customers for our actual cost of fuel with no profit to us. If the cost of fuel goes up, the Maryland Commission permits us to increase the fuel rate. If the cost of fuel goes down, our customers benefit from a reduction in the fuel rate. The fuel rate is impacted most by the amount of electricity generated at the Calvert Cliffs Nuclear Power Plant because the cost of nuclear fuel is cheaper than coal, gas, or oil. (See Note 1 on page 43 for a further discussion of how the fuel rate increases and decreases.) Changes in the fuel rate normally do not affect earnings. However, if the Maryland Commission disallows recovery of any part of the fuel costs, our earnings are reduced. (We discuss this more thoroughly in the "Electric Fuel and Purchased Energy Expenses" section below and in Note 12 on page 54.) In 1996 and 1995, fuel rate revenues decreased due to a lower fuel rate because we were able to operate plants with the lowest fuel costs to generate electricity during the previous 24 months. Fuel rate revenues would have been even lower except we sold more electricity. In 1995, the fuel rate was also lower compared to 1994 because of lower fuel costs. Interchange and Other Sales "Interchange and other sales" are sales of energy in the Pennsylvania-New Jersey-Maryland Interconnection (PJM) and to others. The PJM is a regional power pool of eight utility member companies, including BGE. We sell energy to PJM members and to others after we have satisfied the demand for electricity in our own system. In 1996, we had lower interchange and other sales compared to 1995 because we generated less electricity at our Calvert Cliffs Nuclear Power Plant. This meant that we had less electricity to sell outside of our service territory. We generated less electricity at that plant mostly because the 1996 outage for regular refueling and maintenance took longer than in 1995. In 1995, interchange and other sales increased because we were able to operate plants with the lowest fuel costs to generate electricity, had available capacity, and had lower costs than other utilities. Specifically, we had greater generation from our coal-fired Brandon Shores Power Plant, and our Calvert Cliffs Nuclear Power Plant generated a record level of electricity during 1995. Electric Fuel and Purchased Energy Expenses 1996 1995 1994 - -------------------------------------------------------------------------------- (In millions) Actual costs $539.2 $554.5 $541.2 Net recovery of costs under electric fuel rate clause (see Note 1) 8.2 24.3 1.1 Disallowed replacement energy costs (including carrying charges) (see Note 12) 95.4 -- -- -------------------------- Total electric fuel and purchased energy expenses $642.8 $578.8 $542.3 ========================== Actual Costs In 1996, our actual cost of fuel to generate electricity (nuclear fuel, coal, gas, or oil) and electricity we bought from other utilities was lower than in 1995 because the price of electricity and capacity we bought from other utilities was lower and we sold less electricity. The price we pay for electricity and capacity we buy from other utilities changes based on market conditions, complex pricing formulas for PJM transactions, and contract terms. In 1995, our actual cost of fuel to generate electricity and electricity we bought from other utilities was higher than in 1994 mostly because we generated more electricity and the price of electricity and capacity we bought from other utilities was higher. Our actual costs would have been even higher except we were able to use a less-costly mix of generating plants, mostly because of shorter refueling and maintenance downtime at our Calvert Cliffs Nuclear Power Plant. Electric Fuel Rate Clause The "electric fuel rate clause" (determined by the Maryland Commission) requires that we defer (to include as an asset or liability on the balance sheet and exclude from income and expense) the difference between our actual costs of fuel and our fuel rate revenues collected from customers through the fuel rate. We bill or refund that difference to customers in the future. In 1996 and 1995, our actual fuel costs were lower than the fuel rate revenues we collected from our customers. As a result, we recovered fuel costs which we had deferred in prior years. Disallowed Replacement Energy Costs During 1989 through 1991 we experienced extended outages at our Calvert Cliffs Nuclear Power Plant. These outages have been the subject of ongoing fuel rate proceedings before the Maryland Commission for several years (see Note 12 on page 54). In December 1996, we entered into a settlement agreement with the Maryland People's Counsel and the Maryland Commission Staff. We agreed not to bill our customers for $118 million of electric replacement energy costs associated with these extended outages. We set up a reserve for $35 million of these costs in 1990. In 1996, we increased that reserve by $83 million and we wrote off $5.6 million of related carrying charges. In addition, we wrote off $6.8 million of fuel costs that were disallowed by the Maryland Commission in May 1996 (we discuss these costs further in Note 12 on page 54). These write-offs and the increase in the reserve significantly increased our total purchased fuel and energy expenses in 1996. The remainder of the replacement energy costs associated with the extended outage has already been recovered from customers through the fuel rate. Baltimore Gas and Electric Company and Subsidiaries 27 Gas Operations Gas Revenues The changes in gas revenues in 1996 and 1995 compared to the respective prior year were caused by: 1996 1995 - -------------------------------------------------------------------------------- (In millions) Gas system sales volumes $ 8.2 $ 0.2 Base rates 18.9 6.4 Gas cost adjustments 62.1 (27.4) --------------------- Total change in gas revenues from gas system sales 89.2 (20.8) Off-system sales 26.6 -- Other 1.0 0.1 --------------------- Total change in gas revenues $116.8 $(20.7) ===================== Gas System Sales Volumes The percentage changes in our gas system sales volumes, by type of customer, in 1996 and 1995 compared to the respective prior year were: 1996 1995 - -------------------------------------------------------------------------------- Residential 8.9% (0.2)% Commercial 2.8 1.3 Industrial (2.3) 47 In 1996, we sold more gas to residential and commercial customers due to colder winter and early spring weather and an increase in the number of customers. We would have sold even more gas to those customers except that gas usage per customer decreased. We sold less gas to industrial customers because Bethlehem Steel used less gas. We would have sold even less gas to industrial customers except for increased gas usage by other industrial customers, an increase in the number of customers, and colder winter weather. In 1995, we sold about the same amount of gas to residential customers as we did in 1994. We sold more gas to commercial customers for three reasons: an increase in the number of customers, increased gas usage per customer, and colder weather in the fall of 1995. We would have sold even more gas to commercial customers except for milder weather in the first half of 1995. We sold more gas to industrial customers due to greater gas usage per customer. Base Rates In 1996, base rate revenues were higher than in 1995 because in November 1995, the Maryland Commission allowed us to increase our gas base rates. This increased our annual base rate revenues for 1996 by $19.3 million, or approximately 3.7% of total 1996 gas revenues. That amount included $2.4 million to recover higher depreciation expense (an accounting procedure which spreads the cost of utility plant in service over the years in which it is used). In 1995, our base rate revenues were higher than in 1994 because of the energy conservation surcharge. Gas Cost Adjustments Prior to October 1996, the Maryland Commission allowed us to recover the actual cost of the gas sold to our customers through "gas cost adjustment clauses." These clauses require that we defer the difference between our actual cost of gas and the gas revenues we collect from customers. We bill or refund that difference to customers in the future. Effective October 1996, the Maryland Commission approved a modification of the gas cost adjustment clauses to provide a "Market Based Rates" incentive mechanism. In general terms, under Market Based Rates our actual cost of gas is compared to a market index (a measure of the market price of gas in a given period), and half of the difference belongs to shareholders. We discuss this in more detail in Note 1 on page 43. Delivery service customers, including Bethlehem Steel, are not subject to the gas cost adjustment clauses because we are not selling them gas (we are selling them the service of delivering their gas). In 1996, gas cost revenues increased because we had to pay more for gas and we sold more gas. In 1995, gas cost revenues decreased because we paid less for gas and we sold less gas. Off-System Sales Off-system gas sales, which are direct sales to suppliers and end users of natural gas outside our service territory, also are not subject to gas cost adjustments. We began sales of off-system gas during the first quarter of 1996. The Maryland Commission approved an arrangement for part of the earnings from off-system sales to benefit customers (through reduced costs) and the remainder to be retained by BGE (which benefits shareholders). Gas Purchased For Resale Expenses 1996 1995 1994 - -------------------------------------------------------------------------------- (In millions) Actual costs $295.4 $205.9 $222.7 Net recovery (deferral) of costs under gas adjustment clauses (see Note 1) (11.0) (7.8) 1.9 --------------------------- Total gas purchased for resale expenses $284.4 $198.1 $224.6 =========================== Actual Costs Actual costs include the cost of gas purchased for resale to our customers and for sale off-system. These costs do not include the cost of gas purchased by delivery service customers, including Bethlehem Steel. In 1996, actual gas costs increased from 1995 due to three factors: higher market prices of gas, higher sales volumes, and the purchase of gas to resell off-system (beginning in the first quarter of 1996). In 1995, actual gas costs decreased compared to 1994 because of the considerably lower market price of gas. This decrease would have been even greater except that we received supplier refunds in 1994 which reduced actual gas costs that year. Gas Adjustment Clauses We charge customers for the cost of gas sold through gas adjustment clauses (determined by the Maryland Commission), as discussed under "Gas Cost Adjustments" earlier in this section. In 1996 and 1995, the portion of our actual gas costs subject to these clauses was higher than the revenues we collected from our customers. As a result, we deferred the difference and will collect the costs from our customers in the future. These deferrals decreased our total gas purchased for resale expenses in 1996 and 1995. Baltimore Gas and Electric Company and Subsidiaries 28 Other Operating Expenses Operations and Maintenance Expenses In 1996, our operations and maintenance expenses decreased $18.5 million due to our continued efforts to control costs. This decrease would have been even greater except we had higher costs to maintain our nuclear plant. In 1995, our operations and maintenance expenses were about the same as they were in 1994. Depreciation and Amortization Expenses We describe depreciation and amortization expenses in Note 1 on page 44. In 1996, our depreciation and amortization expense increased $12.8 million from 1995 for two reasons: (bullet) we had more utility plant in service to be depreciated (as our level of utility plant that is in service changes, the amount of our depreciation expense changes), and (bullet) we had more energy conservation program costs to be amortized. The increase in these expenses would have been even greater except that in 1995 depreciation and amortization expense included $14.2 million for the write-off of certain costs of our Perryman site, which is covered in more detail below. In 1996, depreciation and amortization expense did not include any such write-off. In 1995, our depreciation and amortization expense increased $21.5 million over 1994 because we had more utility plant in service to be depreciated (mostly because of some capital additions to our Calvert Cliffs Nuclear Power Plant), and we had a higher level of energy conservation program costs to be amortized. In addition, we completed a study of the cost to decommission Calvert Cliffs. (Decommission is a term used in the nuclear industry for the permanent shut-down of a nuclear power plant which usually occurs when the plant's license expires.) The study resulted in a higher estimated cost of decommissioning, which increased decommissioning expense (included in depreciation and amortization expense) by $9 million annually. Our 1995 and 1994 depreciation and amortization expense reflected the write-off of expenditures associated with future generation facilities at our Perryman site which will not be built. We discuss the write-off of expenditures at our Perryman site further in Note 1 on page 44. The write-off of these costs increased our 1995 depreciation and amortization expense by $14.2 million and increased our 1994 expense by $15.7 million. Taxes Other Than Income Taxes In 1996, taxes (other than income taxes) were $9.6 million higher than in 1995 mostly due to three factors: plant additions made in 1995 increased our property taxes about $7 million, higher 1996 revenues increased our gross receipts taxes about $2 million, and higher labor costs increased our payroll taxes about $1 million. In 1995, taxes (other than income taxes) were $5.4 million higher than in 1994 mostly due to higher property taxes resulting from more utility plant in service. Other Income and Expenses Allowance for Funds Used During Construction (AFC) AFC is an accounting procedure used to exclude the cost of capital from expense and include it as part of the cost of utility plant construction. AFC is calculated at a rate authorized by the Maryland Commission. We describe AFC further in Note 1 on page 44. In 1996 and 1995, we had lower AFC compared to prior years because we completed several projects and started less new construction. In 1996, we also had lower AFC because the Maryland Commission decreased the gas AFC rate in November 1995 from 9.40% to 9.04%. This meant we were not authorized to record as much gas AFC in 1996 as we were in 1995 and 1994. Net Other Income and Deductions Net other income and deductions represent miscellaneous income and expenses which are not directly related to operations. In 1996, net other income and deductions increased $4.9 million compared to 1995 mostly because the Constellation Companies had lower deductions not directly related to operations and BGE had about $2 million more of other interest and finance charge income. In 1995, net other income and deductions decreased $16.2 million compared to 1994 because we had about $12 million less of other interest and finance charge income, and we had about $4 million lower income from the sale of receivables (money customers owe to us) and property. We sell receivables to a financial institution under agreements which are discussed in Note 12 on page 52. Interest Charges Interest charges represent the interest we paid on outstanding debt. In 1996, we had $2.1 million lower interest charges compared to 1995 largely because of lower interest rates. We would have had even lower interest charges except we had more debt outstanding. In 1995, we had $5.3 million higher interest charges compared to 1994 because we had more debt outstanding and short-term interest rates were higher. Income Taxes In 1996 our income taxes decreased because we had lower taxable income from utility operations. Our income taxes would have been even lower except that we had higher taxable income from our diversified businesses. In 1995, our income taxes increased because we had higher taxable income from both our utility operations and our diversified businesses. Environmental Matters We are subject to increasingly stringent federal, state, and local laws and regulations that work to improve or maintain the quality of the environment. If certain substances were disposed of or released at any of our properties, whether currently operating or not, these laws and regulations require us to remove or remedy the effect on the environment. This includes Environmental Protection Agency Superfund sites. You will find details of our environmental matters in Note 12 on page 53 and in this Annual Report on Form 10-K under Item 1. Business - Environmental Matters. These details include financial information. Some of the information is about costs that may be material. Baltimore Gas and Electric Company and Subsidiaries 29 Diversified Businesses In the 1980s, we began to diversify our business in response to limited growth in gas and electric sales. Today, we continue to diversify our business in response to regulatory changes in the utility industry. Some of our diversified businesses are related to our core utility business and others are not. Our diversified businesses include: (bullet) Constellation Holdings, Inc. and Subsidiaries, together known as the Constellation Companies (bullet) BGE Home Products & Services, Inc. and Subsidiary (bullet) BGE Energy Projects & Services, Inc. and Subsidiaries (bullet) Constellation Energy Source, Inc. (formerly named BNG, Inc.) Diversified Business Earnings Per Share of Common Stock 1996 1995 1994 - -------------------------------------------------------------------------------- Constellation Companies $ .29 $ .18 $ .09 BGE Home Products & Services .02 .00 .03 BGE Energy Projects & Services .00 .00 - Constellation Energy Source .00 .00 .00 ------------------------- Total diversified business earnings per share $ .31 $ .18 $ .12 ========================= Our 1996 diversified business earnings increased $19.3 million, or $.13 per share, from 1995. Our 1995 diversified business earnings increased $8.2 million, or $.06 per share, from 1994. These increases mostly reflect higher earnings from the Constellation Companies. We discuss factors affecting the earnings of each diversified business subsidiary below. Constellation Companies' Operations The Constellation Companies engage in the following: (bullet) development, ownership, and operation of power generation projects, (bullet) financial investments, and (bullet) development, ownership, and management of real estate and senior-living facilities. Earnings per share from the Constellation Companies were: 1996 1995 1994 - -------------------------------------------------------------------------------- Power generation $ .18 $ .13 $ .10 Financial investments .14 .08 .03 Real estate development and senior-living facilities (.02) (.02) (.03) Other (.01) (.01) (.01) ------------------------- Total Constellation Companies' earnings per share $ .29 $ .18 $ .09 ========================= Power Generation The Constellation Companies' power generation business develops, owns, and operates power generation facilities. In 1996, earnings increased from 1995 mostly due to our share of higher earnings from energy projects and a $14.6 million after-tax gain on the sale by a Constellation partnership of a power purchase agreement with Jersey Central Power & Light Company back to that utility. Energy projects had higher earnings for a variety of reasons--some ongoing (like improved efficiency due to equipment or procedure changes) and some onetime (for example, losses incurred in 1995--to shut-down certain operations at a plant--did not occur again in 1996). These increases were offset by: (bullet) a $7.0 million after-tax write-off of Constellation's investment in two geothermal wholesale power generating projects, (bullet) a $3.0 million after-tax write-off of development costs for a proposed coal-fired power project that will not be built, and (bullet) a $6.2 million after-tax write-off of a portion of an investment in a solar power project, in which Constellation has a minority ownership interest, expected to be restructured with the lender. In 1995, earnings increased from 1994 mostly due to our share of higher earnings from energy projects and a profit made on the sale of some operating and maintenance contracts. California Power Purchase Agreements The Constellation Companies have $227 million invested in 16 projects that sell electricity in California under power purchase agreements called "Interim Standard Offer No. 4" agreements. Under these agreements, the projects supply electricity to utility companies at: (bullet) a fixed rate for capacity and energy the first 10 years of the agreements, and (bullet) a fixed rate for capacity plus a variable rate for energy based on the utilities' avoided cost for the remaining term of the agreements. Generally, a "capacity rate" is paid to a power plant for its availability to supply electricity, and an "energy rate" is paid for the electricity actually generated. "Avoided cost" generally is the cost of a utility's cheapest next-available source of generation to service the demands on its system. From 1996 through 2000, the 10-year periods for fixed energy rates expire for these 16 power generation projects and they begin supplying electricity at variable rates. When this happens, the revenues at these projects are expected to be lower than they are now. It is difficult to estimate how much lower the revenues may be, but the Constellation Companies' earnings could be affected significantly. Eight projects begin supplying electricity at variable rates in 1997 and 1998. This means the Constellation Companies could experience lower earnings from those projects. However, the remaining projects, which will continue to supply electricity at fixed rates, are expected to have higher revenues in 1997 and 1998. These higher revenues may offset the lower revenues from the variable-rate projects during those years. The California projects that make the highest revenues will begin supplying electricity at variable rates in 1999 and 2000. As a result, we do not expect the Constellation Companies to have significantly lower earnings due to the switch from fixed to variable rates before 2000. Baltimore Gas and Electric Company and Subsidiaries 30 In the second quarter of 1996, Constellation determined that its investments in two of these plants are not expected to be fully recoverable. Accordingly, as mentioned earlier in this section, the Constellation Companies recorded a $7.0 million after-tax write-off of the investment in these plants. Constellation is pursuing alternatives for some of these power generation projects including: (bullet) repowering the projects to reduce operating costs, (bullet) changing fuels to reduce operating costs, (bullet) renegotiating the power purchase agreements to improve the terms, (bullet) restructuring financings to improve the financing terms, and (bullet) selling its ownership interests in the projects. We cannot predict the financial effects of the switch from fixed to variable rates on the Constellation Companies or on BGE, but the effects could be material. International Historically, Constellation's power generation projects have been in the United States. Over the last two years, however, Constellation has sought projects in Latin America. As of December 31, 1996, Constellation had invested about $17.1 million and committed another $6.5 million in power projects in Latin America. In the future, Constellation's power generation business may be expanding further in both domestic and international projects. Financial Investments Earnings from Constellation's portfolio of financial investments include: (bullet) income from marketable securities, (bullet) income from financial limited partnerships, and (bullet) income from financial guaranty insurance companies. In 1996, earnings were higher than in 1995 because of better earnings from marketable securities and increased gains from financial limited partnerships. In 1995, earnings were higher compared to 1994 due to: increased earnings from marketable securities, increased gains from financial limited partnerships, and higher earnings from financial guaranty insurance companies. Real Estate Development and Senior-Living Facilities Constellation's real estate development business includes: (bullet) land under development, (bullet) office buildings, (bullet) retail projects, (bullet) distribution facility projects, (bullet) an entertainment, dining, and retail complex in Orlando, Florida, (bullet) a mixed-use planned-unit development, and (bullet) senior-living facilities. Most of these projects are in the Baltimore-Washington corridor. The area has had a surplus of available land and office space in recent years, during a time of low economic growth and corporate downsizings. Our projects have been economically hurt by these conditions. Earnings from real estate development and senior-living facilities in 1996 and 1995 were essentially unchanged from prior years. Constellation's real estate portfolio has continued to incur carrying costs and depreciation over the years. Additionally, the Constellation Companies have been charging interest payments to expense rather than capitalizing them for some undeveloped land where development activities have stopped. These carrying costs, depreciation, and interest expenses have decreased earnings and are expected to continue to do so. Cash flow from real estate operations has not been enough to make the monthly loan payments on some of these projects. Cash shortfalls have been covered by cash from Constellation Holdings. Constellation Holdings obtained those funds from the cash flow from other Constellation Companies and through additional borrowing. We will consider market demand, interest rates, the availability of financing, and the strength of the economy in general when making decisions about our real estate investments. We believe that until the economy shows sustained growth and there is more demand for new development, our real estate values will not improve much. If we were to sell our real estate projects in the current market, we would have losses, although the amount of the losses is hard to predict. Management's current real estate strategy is to hold each real estate project until we can realize a reasonable value for it. Management evaluates strategies for all its businesses, including real estate, on an ongoing basis.* We anticipate that competing demands for our financial resources, changes in the utility industry, and the proposed merger with Potomac Electric Power Company, will cause us to evaluate thoroughly all diversified business strategies on a regular basis so we use capital and other resources in a manner that is most beneficial. Depending on market conditions in the future, we could also have losses on any future sales. It may be helpful for you to understand when we are required, by accounting rules, to writedown the value of a real estate investment to market value. A writedown is required in either of two cases. The first is if we change our intent about a project from an intent to hold to an intent to sell and the market value of that project is below book value. The second is if the expected cash flow from the project is less than the investment in the project. BGE Home Products & Services' Operations BGE Home Products & Services engages in: (bullet) sales and service of electric and gas appliances, (bullet) home improvements, and (bullet) sales and service of heating and air conditioning systems. In 1996, earnings increased due to improved performance in the service and installation business. In 1995, earnings decreased compared to 1994 largely due to lower income from the sale of receivables during 1995. We sell receivables to a financial institution under agreements which are discussed in Note 12 on page 52. * In the first quarter of 1997, we wrote down the investment in one of our projects to market value because we changed our intent about that project. The write-down is described in detail in the front of this report under The Constellation Companies--Power Generation, Real Estate, and Financial Investments on page 15. Baltimore Gas and Electric Company and Subsidiaries 31 BGE Energy Projects & Services' Operations BGE Energy Projects & Services provides a broad range of customized energy services, including: (bullet) power quality services, (bullet) customer electrical system improvements, (bullet) lighting and mechanical engineering and installation services, (bullet) campus and multi-building energy systems, (bullet) energy consulting and financial contracts, (bullet) district energy systems through Comfort Link (a partnership with the Poole and Kent Company), and (bullet) private electric and gas distribution systems. This subsidiary was formed in November 1995. It had no significant earnings in 1996 or 1995. Constellation Energy Source's Operations Constellation Energy Source (formerly named BNG, Inc.) engages in natural gas brokering. This subsidiary had no significant earnings in 1996 or 1995. - -------------------------------------------------------------------------------- Liquidity and Capital Resources Overview Our business requires a great deal of capital. Our actual capital requirements for the years 1994 through 1996, along with estimated amounts for the years 1997 through 1999, are shown below.
1994 1995 1996 1997 1998 1999 - --------------------------------------------------------------------------------------------------------------------------- (In millions) Utility Business Capital Requirements: Construction expenditures (excluding AFC) Electric $345 $223 $219 $230 $216 $ 215 Gas 68 70 84 72 70 73 Common 42 51 46 33 39 37 ----------------------------------------------------- Total construction expenditures 455 344 349 335 325 325 AFC 34 22 10 7 7 7 Nuclear fuel (uranium purchases and processing charges) 42 46 47 49 50 50 Deferred energy conservation expenditures 41 46 31 24 19 18 Deferred nuclear expenditures 8 -- -- -- -- -- Retirement of long-term debt and redemption of preference stock 203 279 184 173 117 270 ----------------------------------------------------- Total utility business capital requirements 783 737 621 588 518 670 ----------------------------------------------------- Diversified Business Capital Requirements: Investment requirements 51 118 118 214 180 205 Retirement of long-term debt 37 55 52 108 165 186 ----------------------------------------------------- Total diversified business capital requirements 88 173 170 322 345 391 ----------------------------------------------------- Total capital requirements $871 $910 $791 $910 $863 $1,061 =====================================================
Capital Requirements of Our Utility Business Capital requirements for our utility business do not include costs to complete the pending merger with Potomac Electric Power Company. These costs, currently estimated to be $150 million, are discussed in more detail in Note 12 on page 52. We continuously review and change our construction program, so actual expenditures may vary from the estimates for the years 1997 through 1999 in the capital requirements chart. Additionally, actual capital requirements may be different than the estimates for 1997 through 1999 because adjustments which may result from the pending merger with Potomac Electric Power Company have not been considered in those estimates. Electric construction expenditures include: (bullet) installation of a 5,000 kilowatt diesel generator which was placed in service in 1996 at our Calvert Cliffs Nuclear Power Plant, and (bullet) improvements to other generating plants and to our transmission and distribution facilities. Our projections of future electric construction expenditures do not include costs to build more generating units. Our utility operations provided about 96% in 1996, 100% in 1995, and 72% in 1994, of the cash needed to meet our capital requirements, excluding cash needed to retire debt and redeem preferred and preference stock. In addition, in 1994, the sale of some receivables provided $70 million in cash. This is discussed in more detail in Note 12 on page 52. Baltimore Gas and Electric Company and Subsidiaries 32 During the three years from 1997 through 1999, we expect utility operations to provide 115% of the cash needed to meet our capital requirements, excluding cash needed to retire debt and redeem preference stock. This estimate does not consider the pending merger with Potomac Electric Power Company. When we cannot meet utility capital requirements internally, we sell debt and equity securities. The amount of cash we need and market conditions determine when and how much we sell. During the three years ended December 31, 1996, we sold: (bullet) $540 million of long-term debt, (bullet) $60 million of preference stock, and (bullet) $39 million of common stock. Security Ratings Independent credit-rating agencies rate our fixed-income securities. The ratings indicate the agencies' assessment of our ability to pay interest, dividends, and principal on these securities. These ratings affect how much it will cost us to sell these securities. The better the rating, the cheaper it is for us to sell. At the date of this report, our securities ratings were as follows: Standard Moody's & Poor's Investors Duff & Phelps Rating Group Service Credit Rating Co. - -------------------------------------------------------------------------------- Mortgage Bonds A+ A1 AA- Unsecured Debt A A2 A+ Preference Stock A "a2" A Capital Requirements of Our Diversified Businesses In the past, capital requirements of our diversified businesses only included the Constellation Companies because they had the only significant capital requirements. From time to time, however, our other diversified businesses may develop significant capital requirements. As that occurs, we will include the capital requirements of those businesses in the capital requirements table on page 32. As discussed below under "Investment Requirements," capital requirements for Comfort Link are also included this year. Our Constellation Companies and other diversified businesses expect to expand their businesses. This will include our new power marketing business. It also may include expansion in the energy, financial investments, real estate, and senior-living facility businesses. Such expansion could mean more investments in and acquisition of new projects. Our Constellation Companies and other diversified businesses have met their capital requirements in the past through borrowing, cash from their operations, and from time to time, loans or equity contributions from BGE. Our Constellation Companies and other diversified businesses plan to raise the cash needed to meet capital requirements in the future through these same methods. Investment Requirements The investment requirements of our diversified businesses include: (bullet) for the Constellation Companies, investments in financial limited partnerships and funding for the development and acquisition of projects, as well as loans made to project partnerships, and (bullet) for BGE Energy Projects & Services, funding for construction of district energy projects of Comfort Link. Investment requirements for 1997 through 1999 include estimates of funding for existing and new projects and for our new power marketing business. We continuously review and modify those estimates. Actual investment requirements could vary a great deal from the estimates on page 32 because they would be subject to several variables, including: (bullet) the type and number of projects selected for development, (bullet) the effect of market conditions on those projects, (bullet) opportunities for growth in the power marketing business, (bullet) the ability to obtain financing, and (bullet) the availability of cash from operations. Debt and Liquidity Our diversified businesses plan to meet capital requirements by refinancing debt as it comes due, by additional borrowing, and with cash generated by the businesses. This includes cash from operations, sale of assets, and earned tax benefits. BGE Home Products & Services may also meet capital requirements through sales of receivables as discussed in Note 12 on page 52. If Constellation can get a reasonable value for its real estate, it could obtain additional cash by selling real estate projects. For more information, see the discussion of the real estate business and market on page 31. Constellation's ability to sell or liquidate assets will depend on market conditions, and we cannot give assurances that these sales or liquidations could be made. In addition, Constellation has a $75 million revolving credit agreement and Comfort Link has a $50 million revolving credit agreement to provide additional cash for short-term financial needs. Baltimore Gas and Electric Company and Subsidiaries 33 Item 8. Financial Statements and Supplementary Data Report of Independent Accountants 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 as of December 31, 1996 and 1995, 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, 1996, and the consolidated financial statement schedule listed in Item 14(a)(1) and (2) of this Form 10-K. These financial statements and the financial statement schedule are the responsibility of the Company's Management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by Management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Baltimore Gas and Electric Company and Subsidiaries as of December 31, 1996 and 1995, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. In addition, the consolidated financial statement schedule referred to above, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. We have also previously audited, in accordance with generally accepted standards, the consolidated balance sheets and statements of capitalization at December 31, 1994, 1993, and 1992, 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, 1993 (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, 1996, appearing on page 23 is fairly stated in all material respects in relation to the financial statements from which it has been derived. /s/ Coopers & Lybrand L.L.P. _____________________________ COOPERS & LYBRAND L.L.P. Baltimore, Maryland January 17, 1997 34 Consolidated Statements of Income
Year Ended December 31, 1996 1995 1994 - --------------------------------------------------------------------------------------------------------------------------- (In thousands, except per share amounts) Revenues Electric $2,208,744 $2,229,774 $2,126,581 Gas 517,292 400,504 421,249 Diversified businesses 427,211 304,521 235,155 ------------------------------------------------- Total revenues 3,153,247 2,934,799 2,782,985 ------------------------------------------------- Expenses Other Than Interest and Income Taxes Electric fuel and purchased energy 547,414 578,801 542,314 Disallowed replacement energy costs (see Note 12) 95,369 -- -- Gas purchased for resale 284,443 198,069 224,590 Operations 526,424 550,811 552,817 Maintenance 174,141 168,269 164,892 Diversified businesses - selling, general, and administrative 311,053 220,573 167,430 Depreciation and amortization 330,191 317,417 295,950 Taxes other than income taxes 214,747 205,167 199,733 ------------------------------------------------- Total expenses other than interest and income taxes 2,483,782 2,239,107 2,147,726 ------------------------------------------------- Income from Operations 669,465 695,692 635,259 ------------------------------------------------- Other Income Allowance for equity funds used during construction 6,508 14,162 21,746 Equity in earnings of Safe Harbor Water Power Corporation 4,596 4,559 4,349 Net other income and (deductions) (4,974) (9,902) 6,270 ------------------------------------------------- Total other income 6,130 8,819 32,365 ------------------------------------------------- Income Before Interest and Income Taxes 675,595 704,511 667,624 ------------------------------------------------- Interest Expense Interest charges 217,622 219,689 214,347 Capitalized interest (15,664) (15,050) (12,427) Allowance for borrowed funds used during construction (3,520) (7,662) (11,766) ------------------------------------------------- Net interest expense 198,438 196,977 190,154 ------------------------------------------------- Income Before Income Taxes 477,157 507,534 477,470 Income Taxes 166,333 169,527 153,853 ------------------------------------------------- Net Income 310,824 338,007 323,617 Preferred and Preference Stock Dividends 38,536 40,578 39,922 ------------------------------------------------- Earnings Applicable to Common Stock $ 272,288 $ 297,429 $ 283,695 ================================================= Average Shares of Common Stock Outstanding 147,560 147,527 147,100 Earnings Per Share of Common Stock $1.85 $2.02 $1.93 =================================================
See Notes to Consolidated Financial Statements. Baltimore Gas and Electric Company and Subsidiaries 35 Consolidated Balance Sheets
At December 31, 1996 1995 - ---------------------------------------------------------------------------------------------------------------- (In thousands) Assets Current Assets Cash and cash equivalents $ 66,708 $ 23,443 Accounts receivable (net of allowance for uncollectibles of $18,028 and $16,390, respectively) 419,479 400,005 Trading securities 68,794 47,990 Fuel stocks 87,073 59,614 Materials and supplies 147,729 145,900 Prepaid taxes other than income taxes 64,763 60,508 Deferred income taxes 2,943 36,831 Other 44,709 31,487 -------------------------------- Total current assets 902,198 805,778 -------------------------------- Investments and Other Assets Real estate projects 525,765 479,344 Power generation projects 379,130 358,629 Financial investments 204,443 205,841 Nuclear decommissioning trust fund 116,368 85,811 Net pension asset 84,510 60,077 Safe Harbor Water Power Corporation 34,363 34,327 Senior living facilities 36,415 16,045 Other 92,171 71,894 -------------------------------- Total investments and other assets 1,473,165 1,311,968 -------------------------------- Utility Plant Plant in service Electric 6,514,950 6,360,624 Gas 776,973 692,693 Common 523,485 522,450 -------------------------------- Total plant in service 7,815,408 7,575,767 Accumulated depreciation (2,613,355) (2,481,801) -------------------------------- Net plant in service 5,202,053 5,093,966 Construction work in progress 221,857 247,296 Nuclear fuel (net of amortization) 132,937 130,782 Plant held for future use 25,503 25,552 -------------------------------- Net utility plant 5,582,350 5,497,596 -------------------------------- Deferred Charges Regulatory assets (net) 512,279 637,915 Other 80,978 63,406 -------------------------------- Total deferred charges 593,257 701,321 -------------------------------- Total Assets $8,550,970 $8,316,663 ================================
See Notes to Consolidated Financial Statements. Baltimore Gas and Electric Company and Subsidiaries 36 Consolidated Balance Sheets
At December 31, 1996 1995 - -------------------------------------------------------------------------------------------------------------------- (In thousands) Liabilities and Capitalization Current Liabilities Short-term borrowings $ 333,185 $ 279,305 Current portions of long-term debt and preference stock 280,772 146,969 Accounts payable 172,889 177,092 Customer deposits 27,993 26,857 Accrued taxes 6,473 8,244 Accrued interest 57,440 56,670 Dividends declared 66,950 67,198 Accrued vacation costs 34,351 33,403 Other 37,046 39,417 ----------------------------------- Total current liabilities 1,017,099 835,155 ----------------------------------- Deferred Credits and Other Liabilities Deferred income taxes 1,300,174 1,311,530 Postretirement and postemployment benefits 169,253 148,594 Decommissioning of federal uranium enrichment facilities 38,599 43,695 Other 65,463 55,568 ----------------------------------- Total deferred credits and other liabilities 1,573,489 1,559,387 ----------------------------------- Capitalization Long-term debt 2,758,769 2,598,254 Preferred stock -- 59,185 Redeemable preference stock 134,500 242,000 Preference stock not subject to mandatory redemption 210,000 210,000 Common shareholders' equity 2,857,113 2,812,682 ----------------------------------- Total capitalization 5,960,382 5,922,121 ----------------------------------- Commitments, Guarantees, and Contingencies - See Note 12 Total Liabilities and Capitalization $8,550,970 $8,316,663 ===================================
See Notes to Consolidated Financial Statements. Baltimore Gas and Electric Company and Subsidiaries 37 Consolidated Statements of Cash Flows
Year Ended December 31, 1996 1995 1994 - --------------------------------------------------------------------------------------------------------------------------- (In thousands) Cash Flows From Operating Activities Net income $310,824 $338,007 $323,617 Adjustments to reconcile to net cash provided by operating activities Depreciation and amortization 383,155 378,977 351,064 Deferred income taxes 26,009 103,494 79,278 Investment tax credit adjustments (7,655) (8,088) (8,192) Deferred fuel costs 528 5,565 11,461 Deferred energy conservation revenues 28,500 1,283 18,769 Disallowed replacement energy costs 95,369 -- -- Accrued pension and postemployment benefits (13,792) (7,641) (41,113) Allowance for equity funds used during construction (6,508) (14,162) (21,746) Equity in earnings of affiliates and joint ventures (net) (48,305) (21,259) (20,225) Changes in current assets other than sale of accounts receivable (88,035) (107,392) (10,536) Changes in current liabilities, other than short-term borrowings (4,905) (7,293) (24,447) Other 26,762 6,661 (5,699) ---------------------------------------------- Net cash provided by operating activities 701,947 668,152 652,231 ---------------------------------------------- Cash Flows From Financing Activities Proceeds from issuance of Short-term borrowings (net) 53,880 215,605 63,700 Long-term debt 383,182 184,422 207,169 Preference stock -- 59,329 -- Common stock 3,729 318 33,869 Proceeds from sale of receivables 10,000 2,000 70,000 Reacquisition of long-term debt (158,551) (315,105) (240,853) Reacquisition of preferred and preference stock (112,559) (73,000) (4,406) Common stock dividends paid (233,109) (227,192) (220,152) Preferred and preference stock dividends paid (37,050) (40,087) (39,950) Other (1,172) 13 (437) ---------------------------------------------- Net cash used in financing activities (91,650) (193,697) (131,060) ---------------------------------------------- Cash Flows From Investing Activities Utility construction expenditures (including AFC) (360,485) (366,037) (488,976) Allowance for equity funds used during construction 6,508 14,162 21,746 Nuclear fuel expenditures (46,761) (46,330) (42,089) Deferred nuclear expenditures -- -- (8,393) Deferred energy conservation expenditures (31,383) (45,503) (40,440) Contributions to nuclear decommissioning trust fund (25,483) (9,780) (9,780) Purchases of marketable equity securities (32,664) (18,447) (52,099) Sales of marketable equity securities 39,657 49,788 40,585 Other financial investments 7,068 9,423 2,469 Real estate projects (55,344) (15,599) 14,926 Power generation systems (5,332) (34,408) (1,116) Other (62,813) (26,871) (3,650) ---------------------------------------------- Net cash used in investing activities (567,032) (489,602) (566,817) ---------------------------------------------- Net Increase (Decrease) in Cash and Cash Equivalents 43,265 (15,147) (45,646) Cash and Cash Equivalents at Beginning of Year 23,443 38,590 84,236 ---------------------------------------------- Cash and Cash Equivalents at End of Year $ 66,708 $ 23,443 $ 38,590 ============================================== Other Cash Flow Information Cash paid during the year for: Interest (net of amounts capitalized) $182,431 $195,308 $184,441 Income taxes $160,132 $ 99,623 $ 83,143
See Notes to Consolidated Financial Statements. Certain prior-year amounts have been reclassified to conform with the current year's presentation. Baltimore Gas and Electric Company and Subsidiaries 38 Consolidated Statements of Common Shareholders' Equity
Unrealized Gain (Loss) on Available Pension Common Stock Retained For Sale Liability Total Years Ended December 31, 1996, 1995, and 1994 Shares Amount Earnings Securities Adjustment Amount - --------------------------------------------------------------------------------------------------------------------------------- (In thousands) Balance at December 31, 1993 146,034 $1,391,464 $1,251,140 $ -- $(22,093) $2,620,511 Net income 323,617 323,617 Dividends declared Preferred and preference stock (39,922) (39,922) Common stock ($1.51 per share) (222,180) (222,180) Common stock issued 1,493 33,869 33,869 Other 45 45 Net unrealized loss on securities (5,609) (5,609) Deferred taxes on net unrealized loss on securities 1,963 1,963 Pension liability adjustment 8,573 8,573 Deferred taxes on pension liability adjustment (3,001) (3,001) ------------------------------------------------------------------------ Balance at December 31, 1994 147,527 1,425,378 1,312,655 (3,646) (16,521) 2,717,866 Net income 338,007 338,007 Dividends declared Preferred and preference stock (40,578) (40,578) Common stock ($1.55 per share) (228,667) (228,667) Common stock issued 318 318 Other 109 109 Net unrealized gain on securities 14,010 14,010 Deferred taxes on net unrealized gain on securities (4,904) (4,904) Pension liability adjustment 25,417 25,417 Deferred taxes on pension liability adjustment (8,896) (8,896) ------------------------------------------------------------------------ Balance at December 31, 1995 147,527 1,425,805 1,381,417 5,460 -- 2,812,682 Net income 310,824 310,824 Dividends declared Preferred and preference stock (38,536) (38,536) Common stock ($1.59 per share) (234,640) (234,640) Common stock issued 140 3,729 3,729 Other 408 408 Net unrealized gain on securities 4,071 4,071 Deferred taxes on net unrealized gain on securities (1,425) (1,425) ------------------------------------------------------------------------ Balance at December 31, 1996 147,667 $1,429,942 $1,419,065 $8,106 $ -- $2,857,113 ========================================================================
See Notes to Consolidated Financial Statements. Baltimore Gas and Electric Company and Subsidiaries 39 Consolidated Statements of Capitalization
At December 31, 1996 1995 - --------------------------------------------------------------------------------------------------------------------------- (In thousands) Long-Term Debt First Refunding Mortgage Bonds of BGE 5-1/8% Series, due April 15, 1996 $ -- $ 26,187 6-1/8% Series, due August 1, 1997 24,935 24,935 Floating rate series, due April 15, 1999 125,000 125,000 8.40% Series, due October 15, 1999 91,137 91,200 5-1/2% Series, due July 15, 2000 124,990 125,000 8-3/8% Series, due August 15, 2001 122,377 122,427 7-1/8% Series, due January 1, 2002 22,737 39,698 7-1/4% Series, due July 1, 2002 124,484 124,609 5-1/2% Installment Series, due July 15, 2002 10,440 11,045 6-1/2% Series, due February 15, 2003 124,822 124,882 6-1/8% Series, due July 1, 2003 124,855 124,925 5-1/2% Series, due April 15, 2004 124,995 124,995 Remarketed floating rate series, due September 1, 2006 125,000 -- 7-1/2% Series, due January 15, 2007 123,652 123,667 6-5/8% Series, due March 15, 2008 124,960 124,985 7-1/2% Series, due March 1, 2023 124,973 124,973 7-1/2% Series, due April 15, 2023 100,000 100,000 ---------------------------------- Total First Refunding Mortgage Bonds of BGE 1,619,357 1,538,528 ---------------------------------- Other long-term debt of BGE Term bank loan due March 29, 2001 50,000 50,000 Medium-term notes, Series A -- 10,500 Medium-term notes, Series B 100,000 100,000 Medium-term notes, Series C 183,000 200,000 Medium-term notes, Series D 138,000 28,000 Pollution control loan, due July 1, 2011 36,000 36,000 Port facilities loan, due June 1, 2013 48,000 48,000 Adjustable rate pollution control loan, due July 1, 2014 20,000 20,000 5.55% Pollution control revenue refunding loan, due July 15, 2014 47,000 47,000 Economic development loan, due December 1, 2018 35,000 35,000 6.00% Pollution control revenue refunding loan, due April 1, 2024 75,000 75,000 ---------------------------------- Total other long-term debt of BGE 732,000 649,500 ---------------------------------- Long-term debt of Constellation Companies Revolving credit agreement Variable rates based on LIBOR, due December 9, 1999 65,000 1,000 Mortgage and construction loans and other collateralized notes 8.00%, due July 31, 2001 141 -- 8.00%, due October 30, 2003 1,500 -- Variable rates, due through 2009 128,571 110,018 7.50%, due October 9, 2005 9,846 9,989 7.357%, due March 15, 2009 5,763 5,896 9.65%, due February 1, 2028 9,746 -- Unsecured notes 387,160 420,000 ---------------------------------- Total long-term debt of Constellation Companies 607,727 546,903 ---------------------------------- Long-term debt of other diversified businesses Loans under revolving credit agreements 12,000 -- ---------------------------------- Unamortized discount and premium (14,543) (15,708) Current portion of long-term debt (197,772) (120,969) ---------------------------------- Total long-term debt $2,758,769 $2,598,254 ----------------------------------
continued on page 41 See Notes to Consolidated Financial Statements. Baltimore Gas and Electric Company and Subsidiaries 40 Consolidated Statements of Capitalization
At December 31, 1996 1995 - --------------------------------------------------------------------------------------------------------------------------- (In thousands) Preferred Stock Cumulative, $100 par value, 1,000,000 shares authorized Series B, 4 1/2%, 222,921 shares redeemed at $110 per share on May 28, 1996 $ -- $ 22,292 Series C, 4%, 68,928 shares redeemed at $105 per share on May 28, 1996 -- 6,893 Series D, 5.40%, 300,000 shares redeemed at $101 per share on May 28, 1996 -- 30,000 ---------------------------------- Total preferred stock -- 59,185 ---------------------------------- Preference Stock Cumulative, $100 par value, 6,500,000 shares authorized Redeemable preference stock 7.50%, 1986 Series, 395,000 and 425,000 shares outstanding. Callable at $102.50 per share prior to October 1, 2001 and at lesser amounts thereafter 39,500 42,500 6.75%, 1987 Series, 440,000 and 455,000 shares outstanding. Callable at $104.50 per share prior to April 1, 1997 and at lesser amounts thereafter 44,000 45,500 7.80%, 1989 Series, 500,000 shares outstanding 50,000 50,000 8.25%, 1989 Series, 100,000 and 300,000 shares outstanding 10,000 30,000 8.625%, 1990 Series, 390,000 and 650,000 shares outstanding 39,000 65,000 7.85%, 1991 Series, 350,000 shares outstanding 35,000 35,000 Current portion of redeemable preference stock (83,000) (26,000) ---------------------------------- Total redeemable preference stock 134,500 242,000 ---------------------------------- Preference stock not subject to mandatory redemption 7.78%, 1973 Series, 200,000 shares outstanding, callable at $101 per share 20,000 20,000 7.125%, 1993 Series, 400,000 shares outstanding, not callable prior to July 1, 2003 40,000 40,000 6.97%, 1993 Series, 500,000 shares outstanding, not callable prior to October 1, 2003 50,000 50,000 6.70%, 1993 Series, 400,000 shares outstanding, not callable prior to January 1, 2004 40,000 40,000 6.99%, 1995 Series, 600,000 shares outstanding, not callable prior to October 1, 2005 60,000 60,000 ---------------------------------- Total preference stock not subject to mandatory redemption 210,000 210,000 ---------------------------------- Common Shareholders' Equity Common stock without par value, 175,000,000 shares authorized; 147,667,114 and 147,527,114 shares issued and outstanding at December 31, 1996 and 1995, respectively. (At December 31, 1996, 166,893 shares were reserved for the Employee Savings Plan and 3,277,656 shares were reserved for the Dividend Reinvestment and Stock Purchase Plan.) 1,429,942 1,425,805 Retained earnings 1,419,065 1,381,417 Unrealized gain (loss) on available-for-sale securities 8,106 5,460 ---------------------------------- Total common shareholders' equity 2,857,113 2,812,682 ---------------------------------- Total Capitalization $5,960,382 $5,922,121 ==================================
See Notes to Consolidated Financial Statements. Baltimore Gas and Electric Company and Subsidiaries 41 Consolidated Statements of Income Taxes
Year Ended December 31, 1996 1995 1994 - ---------------------------------------------------------------------------------------------------------------------------------- (Dollar amounts in thousands) Income Taxes Current $147,979 $ 74,121 $ 82,767 ------------------------------------------------- Deferred Change in tax effect of temporary differences 22,516 118,300 88,896 Change in income taxes recoverable through future rates 4,918 (1,006) (8,580) Deferred taxes credited (charged) to shareholders' equity (1,425) (13,800) (1,038) ------------------------------------------------- Deferred taxes charged to expense 26,009 103,494 79,278 Investment tax credit adjustments (7,655) (8,088) (8,192) ------------------------------------------------- Income taxes per Consolidated Statements of Income $166,333 $169,527 $153,853 ================================================= Reconciliation of Income Taxes Computed at Statutory Federal Rate to Total Income Taxes Income before income taxes $477,157 $507,534 $477,470 Statutory federal income tax rate 35% 35% 35% ------------------------------------------------- Income taxes computed at statutory federal rate 167,005 177,637 167,115 Increases (decreases) in income taxes due to Depreciation differences not normalized on regulated activities 12,669 10,953 9,791 Allowance for equity funds used during construction (2,278) (4,957) (7,611) Amortization of deferred investment tax credits (7,655) (8,088) (8,164) Tax credits flowed through to income (520) (521) (1,754) Amortization of deferred tax rate differential on regulated activities (1,958) (2,013) (1,885) Other (930) (3,484) (3,639) ------------------------------------------------- Total income taxes $166,333 $169,527 $153,853 ================================================= Effective federal income tax rate 34.9% 33.4% 32.2%
At December 31, 1996 1995 - ------------------------------------------------------------------------------------------------------------------- (Dollar amounts in thousands) Deferred Income Taxes Deferred tax liabilities Accelerated depreciation $ 920,631 $ 878,470 Allowance for funds used during construction 209,183 210,928 Income taxes recoverable through future rates 92,584 94,305 Deferred termination and postemployment costs 45,624 49,591 Deferred fuel costs 7,957 39,559 Leveraged leases 27,581 29,842 Percentage repair allowance 38,354 38,295 Energy conservation expenditures 26,622 28,121 Other 175,587 151,231 ---------------------------------- Total deferred tax liabilities 1,544,123 1,520,342 ---------------------------------- Deferred tax assets Alternative minimum tax -- 32,626 Accrued pension and postemployment benefit costs 40,570 31,707 Deferred investment tax credits 46,889 49,512 Capitalized interest and overhead 42,509 39,439 Contributions in aid of construction 35,710 34,404 Nuclear decommissioning liability 18,750 16,708 Other 62,464 41,247 ---------------------------------- Total deferred tax assets 246,892 245,643 ---------------------------------- Deferred tax liability, net $1,297,231 $1,274,699 ==================================
See Notes to Consolidated Financial Statements. Baltimore Gas and Electric Company and Subsidiaries 42 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 ten 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 are eliminated in consolidation. Under this policy, the accounts of Constellation Holdings, Inc. (CHI) and Subsidiaries (collectively, the Constellation Companies), BGE Home Products & Services, Inc. and Subsidiary (collectively, HP&S), BGE Energy Projects & Services, Inc. and Subsidiaries (collectively, EP&S), and Constellation Energy Source, Inc. (formerly named 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 (which include power generation projects) 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 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 Mary-land Public Service Commission (Maryland Commission). 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 The cost of fuel used in generating electricity, net of revenues from interchange sales, is recovered through a zero-based electric fuel rate subject to approval by the Maryland Commission. The difference between actual fuel costs and fuel revenues is deferred on the Consolidated Balance Sheets 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. During 1989 through 1991 BGE experienced extended outages at its Calvert Cliffs Nuclear Power Plant. The replacement energy costs associated with these outages are estimated to be $458 million. The extended outages have been the subject of ongoing fuel rate proceedings before the Maryland Commission for several years (see Note 12). In December 1996, BGE entered into a settlement agreement with the Maryland People's Counsel and the Maryland Commission Staff proposing that customers will not fund a total of $118 million of electric replacement energy costs associated with these extended outages. BGE recorded a reserve for $35 million of these costs in 1990. In 1996, BGE increased the reserve by $83 million and wrote off $5.6 million of accrued carrying charges related to the deferred fuel balances. These increases in the reserve reduced 1996 after-tax earnings by $57.6 million, or 39 cents per share. In addition, the Maryland Commission issued a rate order in May 1996 disallowing certain fuel costs which were previously deferred by BGE. Accordingly, BGE wrote-off the deferred fuel costs in 1996. The write-off of these costs reduced after-tax earnings by $4.5 million, or 3 cents per share. Prior to October 1996, the cost of gas sold was recovered through gas adjustment clauses subject to approval by the Maryland Commission. Under these clauses, the difference between actual fuel costs and fuel revenues is deferred on the balance sheet and recovered from or refunded to customers in future periods. Effective October 1996, the Maryland Commission approved a modification of these clauses to provide a Market Based Rates (MBR) incentive mechanism. Under the MBR mechanism, differences between a market index and BGE's actual cost of gas are shared equally between BGE's customers and shareholders. Risk Management Beginning in 1996, BGE engages in commodity hedging activities to minimize the risk of market fluctuations associated with the price of gas under the MBR mechanism. The objective of hedging is to manage BGE's price risk under the MBR mechanism. Under internal guidelines, speculative positions are prohibited. BGE enters into basis swap agreements which help minimize commodity price risk by fixing the basis or differential that exists between a delivery location index and the commodity futures prices. Net amounts receivable or payable under the swaps are deferred and recognized as a component of gas costs when realized. At December 31, 1996, there were unsettled swap agreements representing a notional quantity of 12.3 million decatherms of natural gas purchases through March 1997. 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. That portion has been recorded as a regulatory asset on the Consolidated Balance Sheets. 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 less applicable tax credits. 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. Current income tax for the years ended December 31, 1996 and 1995 reflect full utilization of AMT credits carried forward of $30 million and $40 million, respectively. The deferred income taxes provided in earlier years on the AMT liability were reversed as the credits were utilized. The investment tax credit (ITC) associated with BGE's regulated utility operations has been deferred on the Consolidated Balance Sheets (see Note 5) 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. Baltimore Gas and Electric Company and Subsidiaries 43 Inventory Valuation Fuel stocks and materials and supplies are generally stated at average cost. Impairment of Long-Lived Assets Long-lived assets subject to the requirements of Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, are evaluated for impairment through a review of undiscounted expected future cash flows. If the sum of the undiscounted expected future cash flows is less than the carrying amount of the asset, an impairment loss is recognized. Real Estate Projects Real estate projects consist of the Constellation Companies' investments 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 subsequent 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 Investments in debt and equity securities subject to the requirements of Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities, are reported at fair value. Certain of Constellation Companies' marketable equity securities and financial partnerships are classified as trading securities. Unrealized gains and losses on these securities 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. The Company utilizes specific identification to determine the cost of these securities in computing realized gains or losses. 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. As a result of the Maryland Commission's November 1995 gas rate Order, BGE revised its gas utility plant depreciation rates to reflect the results of a detailed depreciation study. The revised rates resulted in an increase in depreciation accruals of approximately $2.4 million annually. Depreciation expense for 1995 and 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 its Perryman site with each unit consisting of two combustion turbines. However, due to significant changes in the environment in which utilities operate, BGE decided in 1994 not to construct the second combined cycle generating unit and wrote off the construction work in progress costs associated with that unit. This write-off reduced after-tax earnings during 1994 by $11.0 million or 7 cents per share. As a result of the Maryland Commission's August 1995 Order requiring all new generation capacity needs to be competitively bid and BGE's September 1995 announcement that it will merge with Potomac Electric Power Company, BGE determined that it will not build the second combustion turbine for the first combined cycle unit. Therefore, during the third quarter of 1995, BGE wrote off the remaining construction work in progress costs associated with the first combined cycle unit. This write-off reduced after-tax earnings during 1995 by $9.7 million, or 7 cents per share. The construction of the first 140-megawatt combustion turbine at Perryman was completed, and the unit was placed in service, during June 1995. 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 $153 million and $150 million as of December 31, 1996 and 1995, respectively. 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 nuclear 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 a 1995 order, the Maryland Commission authorized BGE to record decommissioning expense based on a facility-specific cost estimate in order to accumulate a decommissioning reserve of $521 million in 1993 dollars by the end of Calvert Cliffs' service life in 2016, adjusted to reflect expected inflation, to decommission the radioactive portion of the plant. The total decommissioning reserve of $163.8 million and $136.7 million at December 31, 1996 and 1995, 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. BGE is using the facility-specific cost estimate 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 Consolidated Balance Sheets, crediting the cost as a noncash item on the Consolidated Statements of Income. 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 November 20, 1995, the Company accrued AFC at a pre-tax rate of 9.40%. Effective November 20, 1995, a rate order of the Maryland Commission reduced the pre-tax gas-plant and common-plant AFC rates to 9.04% and 9.36%, respectively. AFC is compounded annually. The Constellation Companies capitalize interest on qualifying real estate and power generation development projects. Baltimore Gas and Electric Company and Subsidiaries 44 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. Use of Accounting Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. These estimates involve judgments with respect to, among other things, various future economic factors which are difficult to predict and are beyond the control of the Company. Therefore, actual amounts could differ from these estimates. Accounting Standards Issued The Financial Accounting Standards Board has issued Statement of Financial Accounting Standards No. 125, regarding accounting for transfers and servicing of financial assets and extinguishments of liabilities, effective January 1, 1997. The American Institute of Certified Public Accountants has issued Statement of Position No. 96-1, regarding accounting for environmental remediation liabilities, effective January 1, 1997. Adoption of these statements is not expected to have a material impact on the Company's financial statements. - -------------------------------------------------------------------------------- Note 2. Segment Information
Construction Identifiable Nonaffiliated Affiliated Total Income from Depreciation/ Expenditures Assets at Revenues Revenues Revenues Operations Amortization (Including AFC) December 31 - --------------------------------------------------------------------------------------------------------------------------------- (In thousands) 1996 Electric $2,208,744 $ 283 $2,209,027 $497,986 $279,345 $262,542 $6,226,291 Gas 517,292 -- 517,292 68,848 37,790 97,943 810,084 Diversified businesses 427,211 6,782 433,993 102,631 13,056 -- 1,400,553 Other identifiable assets -- -- -- -- -- -- 114,042 Intercompany eliminations -- (7,065) (7,065) -- -- -- -- ------------------------------------ -------- -------- -------- ---------- Total $3,153,247 $ -- $3,153,247 $669,465 $330,191 $360,485 $8,550,970 ==================================== ======== ======== ======== ========== 1995 Electric $2,229,774 $ 1,337 $2,231,111 $574,299 $276,285 $288,509 $6,195,722 Gas 400,504 -- 400,504 48,104 29,637 77,528 748,462 Diversified businesses 304,521 6,609 311,130 73,289 11,495 -- 1,266,049 Other identifiable assets -- -- -- -- -- -- 106,430 Intercompany eliminations -- (7,946) (7,946) -- -- -- -- ------------------------------------ -------- -------- -------- ---------- Total $2,934,799 $ -- $2,934,799 $695,692 $317,417 $366,037 $8,316,663 ==================================== ======== ======== ======== ========== 1994 Electric $2,126,581 $ 840 $2,127,421 $539,739 $252,273 $412,885 $5,981,634 Gas 421,249 -- 421,249 27,801 32,478 76,091 726,759 Diversified businesses 235,155 8,245 243,400 67,719 11,199 -- 1,200,551 Other identifiable assets -- -- -- -- -- -- 128,558 Intercompany eliminations -- (9,085) (9,085) -- -- -- -- ------------------------------------ -------- -------- -------- ---------- Total $2,782,985 $ -- $2,782,985 $635,259 $295,950 $488,976 $8,037,502 ==================================== ======== ======== ======== ==========
- -------------------------------------------------------------------------------- Note 3. Subsidiary Information Diversified businesses consist of the operations of the Constellation Companies, HP&S, EP&S, and Constellation Energy Source, Inc. (formerly named BNG, Inc.). The Constellation Companies include Constellation Holdings, Inc., a wholly owned subsidiary which holds all of the stock of three other subsidiaries, Constellation Power, Inc. (formerly named Constellation Energy, Inc.), Constellation Investments, Inc., and Constellation Real Estate Group, Inc. These companies are engaged in development, ownership, and operation of power generation projects; financial investments; and development, ownership, and management of real estate and senior-living facilities, respectively. HP&S is a wholly owned subsidiary which engages predominantly in the sales and service of electric and gas appliances, home improvements, and sales and service of heating and air conditioning systems, primarily in Central Maryland. EP&S is a wholly owned subsidiary which provides a broad range of customized energy services. These energy services include: power quality services, customer electrical system improvements, lighting and mechanical engineering and installation services, campus and multi-building energy systems, energy consulting and financial contracts, district energy systems through Comfort Link (a partnership with the Poole and Kent Company), and, beginning in late 1996, private electric and gas distribution systems. Constellation Energy Source, Inc. (formerly named 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 the Constellation Companies. The condensed financial information does not reflect the elimination of intercompany balances or transactions which are eliminated in the Company's consolidated financial statements. Baltimore Gas and Electric Company and Subsidiaries 45 The 1996 operating results reflect a $14.6 million after-tax gain on the sale by a Constellation partnership of a power purchase agreement with Jersey Central Power & Light Company back to that utility. This gain was offset by a $7.0 million after-tax write-off of the investment in two geothermal wholesale power generating projects, a $3.0 million after-tax write-off of development costs of a proposed coal-fired power project that will not be built, and a $6.2 million after-tax write-off of a portion of an investment in a solar power project in which the Constellation Companies have a minority ownership interest and which is expected to be restructured with the lender.
1996 1995 1994 - -------------------------------------------------------------------------------------------------------------------------- (In thousands, except per share amounts) Income Statements Revenues Real estate projects $ 80,793 $ 108,414 $ 106,915 Power generation systems 93,134 57,734 41,301 Financial investments 38,916 25,201 12,126 --------------------------------------------------- Total revenues 212,843 191,349 160,342 Expenses other than interest and income taxes 113,247 114,479 107,267 --------------------------------------------------- Income from operations 99,596 76,870 53,075 Minority interest (355) (2,348) -- Interest expense (44,991) (46,673) (45,782) Capitalized interest 14,645 13,582 10,776 Income tax benefit (expense) (26,578) (14,355) (4,305) --------------------------------------------------- Net income $ 42,317 $ 27,076 $ 13,764 =================================================== Contribution to the Company's earnings per share of common stock $ .29 $ .18 $ .09 =================================================== Balance Sheets Current assets $ 115,689 $ 98,526 $ 92,814 Noncurrent assets 1,189,726 1,102,528 1,055,056 --------------------------------------------------- Total assets $1,305,415 $1,201,054 $1,147,870 --------------------------------------------------- Current liabilities $ 134,025 $ 70,393 $ 70,670 Noncurrent liabilities 775,237 778,505 758,626 Shareholder's equity 396,153 352,156 318,574 --------------------------------------------------- Total liabilities and shareholder's equity $1,305,415 $1,201,054 $1,147,870 ===================================================
- -------------------------------------------------------------------------------- Note 4. Real Estate Projects and Financial Investments Real Estate Projects Real estate projects consist of the following investments held by the Constellation Companies: At December 31, 1996 1995 - ----------------------------------------------------------- (In thousands) Properties under development $286,200 $270,678 Rental and operating properties (net of accumulated depreciation) 237,725 207,666 Other real estate ventures 1,840 1,000 ----------------------- Total real estate projects $525,765 $479,344 ======================= Financial Investments Financial investments consist of the following investments held by the Constellation Companies: At December 31, 1996 1995 - --------------------------------------------------------- (In thousands) Insurance companies $ 76,822 $ 77,792 Marketable equity securities 46,231 41,475 Financial limited partnerships 48,115 51,023 Leveraged leases 33,275 35,551 ----------------------- Total financial investments $204,443 $205,841 ======================= Available-For-Sale Investments The Constellation Companies' marketable equity securities shown above and BGE's investments comprising the nuclear decommissioning trust fund are classified as available-for-sale. The fair values, gross unrealized gains and losses, and amortized cost bases for available-for-sale securities, exclusive of $1.9 million of unrealized net gains on securities of equity-method investees, are as follows: Amortized Unrealized Unrealized Fair At December 31, 1996 Cost Basis Gains Losses Value - ------------------------------------------------------------------- (In thousands) Marketable equity $ 39,363 $6,918 $ (50) $ 46,231 securities U.S. government agency 18,167 263 -- 18,430 State municipal bonds 73,571 2,202 (125) 75,648 ----------------------------------------- Total $131,101 $9,383 $(175) $140,309 ========================================= Amortized Unrealized Unrealized Fair At December 31, 1995 Cost Basis Gains Losses Value - ------------------------------------------------------------------- (In thousands) Marketable equity securities $ 38,520 $2,998 $ (43) $ 41,475 U.S. government agency 14,177 141 -- 14,318 State municipal bonds 50,411 2,056 (74) 52,393 ------------------------------------------ Total $103,108 $5,195 $(117) $108,186 ========================================== Baltimore Gas and Electric Company and Subsidiaries 46 Gross and net realized gains and losses on the Constellation Companies' available-for-sale securities were as follows: 1996 1995 1994 - ------------------------------------------------------------- (In thousands) Gross realized gains $4,280 $5,470 $ 1,108 Gross realized losses (210) (2,446) (3,150) ------------------------------- Net realized gains (losses) $4,070 $3,024 $(2,042) =============================== Contractual Maturities The contractual maturities of debt securities are as follows: Amount - ---------------------------------------------------------- (In thousands) Less than 1 year $ 1,000 1-5 years 10,065 5-10 years 71,405 More than 10 years 6,000 ------- Total contractual maturities of debt securities $88,470 ======= - -------------------------------------------------------------------------------- Note 5. Regulatory Assets (net) As discussed in Note 1, BGE's utility operations are subject to regulation by the Maryland Commission. Except for differences in the timing of the recognition of certain utility expenses and credits, the ratemaking process utilized by the Maryland Commission generally is based upon the same accounting principles applied by nonregulated entities. Under the Maryland Commission's ratemaking process, these utility expenses and credits are deferred on the Consolidated Balance Sheets 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 and liabilities: At December 31, 1996 1995 - ------------------------------------------------------------------ (In thousands) Income taxes recoverable through future rates $264,525 $269,442 Deferred postemployment benefit costs 89,217 81,616 Deferred nuclear expenditures 82,101 86,519 Deferred environmental costs 47,657 38,371 Deferred energy conservation expenditures 46,696 73,297 Deferred cost of decommissioning federal uranium enrichment facilities 46,015 51,104 Deferred termination benefit costs 41,137 60,073 Deferred fuel costs 22,734 113,026 Deferred investment tax credits (133,970) (141,463) Other 6,167 5,930 -------------------- Total regulatory assets (net) $512,279 $637,915 ==================== 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 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 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 Maryland Commission. 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 environmental costs represent the estimated costs of investigating contamination and performing certain remediation activities at contaminated Company-owned sites (see Note 12). In November 1995, the Maryland Commission issued a rate order in the Company's gas base rate proceeding which authorized the Company to amortize over a 10-year period $21.6 million of these costs, the amount which had been incurred through October 1995. 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 Maryland Commission. These expenditures consist of labor, materials, and indirect costs associated with the conservation programs approved by the Maryland Commission. 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 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 Maryland Commission. 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, 1996 1995 - -------------------------------------------------------------------- (In thousands) Electric deferred fuel costs Costs deferred $113,172 $130,399 Reserve for disallowed replacement energy costs (see Note 12) (118,000) (35,000) -------------------- Net electric deferred fuel costs (4,828) 95,399 Gas deferred fuel costs 27,562 17,627 -------------------- Total deferred fuel costs $ 22,734 $113,026 ==================== Deferred investment tax credits (ITC) represents ITC associated with BGE's regulated utility operations as discussed in Note 1. Deferred ITC are not deducted from rate base in accordance with federal income tax normalization requirements. The foregoing regulatory assets and liabilities are recorded on BGE's Consolidated Balance Sheets in accordance with Statement of Financial Accounting Standards (SFAS) No. 71. If BGE were required to terminate application of SFAS No. 71 for all of its regulated operations, all such amounts deferred would be recognized in the Consolidated Statements of Income at that time, resulting in a charge to earnings, net of applicable income taxes. Baltimore Gas and Electric Company and Subsidiaries 47 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 BGE's subsidiaries. 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, 1996 consisted primarily of marketable equity and fixed income securities, and group annuity contracts. The following tables set forth the combined funded status of the plans and the composition of total net pension cost. Net pension cost shown below does not include the cost of termination benefits described in Note 7.
At December 31, 1996 1995 - ------------------------------------------------------------------------------------------------------------------------ (In thousands) Vested benefit obligation $695,634 $688,084 Nonvested benefit obligation 17,974 15,668 ---------------------------------- Accumulated benefit obligation 713,608 703,752 Projected benefits related to increase in future compensation levels 132,673 122,539 ---------------------------------- Projected benefit obligation 846,281 826,291 Plan assets at fair value (792,541) (744,645) ---------------------------------- Projected benefit obligation less plan assets 53,740 81,646 Unrecognized prior service cost (21,890) (24,357) Unrecognized net loss (117,157) (118,361) Unamortized net asset from adoption of FASB Statement No. 87 797 995 ---------------------------------- Accrued pension (asset) liability $ (84,510) $ (60,077) ==================================
Year Ended December 31, 1996 1995 1994 - --------------------------------------------------------------------------------------------------------------------------- (In thousands) Components of net pension cost Service cost-benefits earned during the period $16,089 $11,407 $15,015 Interest cost on projected benefit obligation 59,948 58,433 58,723 Actual return on plan assets (57,671) (150,510) 7,932 Net amortization and deferral 2,115 94,674 (60,071) ------------------------------------------------ Total net pension cost 20,481 14,004 21,599 Amount capitalized as construction cost (2,442) (1,422) (2,578) ------------------------------------------------ Amount charged to expense $18,039 $12,582 $19,021 ================================================
The Company also sponsors a defined contribution savings plan covering all eligible BGE employees and certain employees of BGE's subsidiaries. Under this plan, the Company makes contributions on behalf of participants. Company contributions to this plan totaled $9.4 million, $8.5 million, and $8.7 million in 1996, 1995, and 1994, 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 its subsidiaries. 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. The transition obligation resulting from the adoption of Statement of Financial Accounting Standards No. 106 effective January 1, 1993 is being amortized over a 20-year period. In April 1993, the Maryland Commission 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 April 1993 Order, 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 November 1995, the Maryland Commission issued a rate order in BGE's gas base rate proceeding providing for full recognition in operating expense of PRB and other postemployment benefits (discussed below) costs attributable to gas operations, and affirming its previous decision on amortization of deferred PRB costs. This phase-in approach meets the guidelines established by the Emerging Issues Task Force of the Financial Accounting Standards Board for deferring PRB costs as a regulatory asset. Accrual-basis PRB costs applicable to nonregulated operations are charged to expense. Baltimore Gas and Electric Company and Subsidiaries 48 The following table sets forth the components of the accumulated PRB obligation and a reconciliation of these amounts to the accrued PRB liability.
At December 31, 1996 1995 - --------------------------------------------------------------------------------------------------------------------------- Life Life Health Care Insurance Health Care Insurance (In thousands) Accumulated postretirement benefit obligation: Retirees $163,904 $45,485 $157,804 $44,769 Active employees 82,373 19,269 84,724 18,599 ------------------------------------------------------------- Total accumulated postretirement benefit obligation 246,277 64,754 242,528 63,368 Unrecognized transition obligation (141,089) (40,960) (149,907) (43,521) Unrecognized net loss (7,368) (5,690) (12,767) (5,764) ------------------------------------------------------------- Accrued postretirement benefit liability $ 97,820 $18,104 $ 79,854 $14,083 =============================================================
The following table sets forth the composition of net PRB cost. Such cost does not include the cost of termination benefits described in Note 7. Year ended December 31, 1996 1995 - -------------------------------------------------------------------------------- (In thousands) Net postretirement benefit cost: Service cost--benefits earned during the period $ 5,559 $ 3,918 Interest cost on accumulated post retirement benefit obligation 21,918 21,203 Amortization of transition obligation 11,378 11,378 Net amortization and deferral 174 (86) ------------------- Total net postretirement benefit cost 39,029 36,413 Amount capitalized as construction cost (6,224) (5,299) Amount deferred (7,455) (8,025) ------------------- Amount charged to expense $25,350 $23,089 =================== Other Postemployment Benefits The Company provides health and life insurance benefits to employees of BGE and certain employees of its subsidiaries who are determined to be disabled under BGE's Disability Insurance Plan. The Company also provides pay continuation payments for employees determined to be disabled before November 1995. Such payments for employees determined to be disabled after that date are paid by an insurance company, and the cost of such insurance is paid by employees. The liability for these benefits totaled $51 million and $52 million as of December 31, 1996 and 1995, respectively. The portion of the liability attributable to regulated activities as of December 31, 1993 was deferred. Consistent with the Maryland Commission's November 1995 order, the amounts deferred will be amortized over a 15-year period beginning in 1998. Assumptions The pension, postretirement, and other postemployment benefit liabilities were determined using the following assumptions. At December 31, 1996 1995 - -------------------------------------------------------------------------------- Assumptions: Discount rate Pension and postretirement benefits 7.5% 7.5% Other postemployment benefits 6.0 6.0 Average increase in future compensation levels 4.0 4.0 Expected long-term rate of return on assets 9.0 9.0 The health care inflation rates for 1996 are assumed to be 9.5% for Medicare-eligible retirees and 8.9% for retirees not covered by Medicare. The health care inflation rates for 1997 are assumed to be 7.5% for Medicare-eligible retirees and 10.0% for retirees not covered by Medicare. After 1997, 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 $41 million as of December 31, 1996 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 April 1993, the Maryland Commission authorized BGE to amortize the $6.6 million cost of termination benefits associated with the 1992 VSERP, which consisted principally of an enhanced pension benefit, over a five-year period for ratemaking purposes. 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. 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 Maryland Commission. Baltimore Gas and Electric Company and Subsidiaries 49 Note 8. Short-Term Borrowings Short-term borrowings include bank loans, commercial paper notes, and bank lines of credit. The Company pays commitment fees in support of lines of credit. Borrowings under the lines are at the banks' prime rates, base interest rates, or at various money market rates. Short-term borrowings were as follows: At December 31, 1996 1995 - ------------------------------------------------------------------- (In thousands) BGE's bank loans $ 8,785 $ 3,845 BGE's commercial paper notes 324,400 275,300 Constellation Companies' lines of credit -- 160 -------------------- Total short-term borrowings $333,185 $279,305 ==================== The weighted average interest rates for short-term borrowings were as follows: Year ended December 31, 1996 1995 - ------------------------------------------------------------------- BGE Bank loans 4.93% 4.74% Commercial Paper Notes 5.53 5.92 Constellation Companies Lines of Credit -- -- Unused lines of credit supporting commercial paper notes at December 31, 1996 and 1995 were $203 million and $238 million, respectively. These amounts are exclusive of $150 million of revolving credit agreements undrawn at year-end (see Note 9). - -------------------------------------------------------------------------------- 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, HP&S, EP&S, and Constellation Energy Source, Inc. (formerly named 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 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. The principal amounts of the 5 1/2% Installment Series Mortgage Bonds payable each year are as follows: Year - -------------------------------------------------------------------------------- (In thousands) 1997 $ 605 1998 and 1999 690 2000 and 2001 865 2002 6,725 The Remarketed Floating Rate Series Due September 1, 2006 First Refunding Mortgage Bonds include a provision that allows the bondholders the option to tender their bonds back to BGE on an annual basis. BGE is required to repurchase and retire at par any bonds tendered that are not remarketed or purchased by the remarketing agent. In addition, BGE has the option to call the bonds annually at par on each remarketing date. Other Long-Term Debt of BGE BGE maintains revolving credit agreements that expire at various times from 1997 through 1999. 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, 1996, BGE had no borrowings under these revolving credit agreements and had available $150 million of unused capacity under these agreements. Under the terms of the bank loan which matures on March 29, 2001, the bank has a one-time option to cancel the loan on December 29, 1997. Until that date, the interest rate on the loan is 5.22%. If the bank does not cancel the loan on December 29, 1997, the interest rate for the remaining term will reset to 6.11%. Following is information regarding BGE's Medium-term Notes outstanding at December 31, 1996: Weighted-Average Series Interest Rate Maturity Dates - -------------------------------------------------------------------------------- B 8.43% 1998-2006 C 7.09% 1997-2003 D 6.60% 1998-2006 Long-Term Debt of Constellation Companies The Constellation Companies have a $75 million unsecured revolving credit agreement which matures December 9, 1999 and is used to provide liquidity for general corporate purposes. A commitment fee is paid on the daily average of the unborrowed portion of the commitment. At December 31, 1996, the Constellation Companies had $65 million outstanding under this agreement. The Constellation Companies' mortgage and construction loans and other collateralized notes have varying terms. The 8.00% mortgage note requires monthly principal and interest payments through July 31, 2001. The 8.00% construction loan requires no monthly principal and interest payments during construction and is due October 30, 2003. The variable rate mortgage notes require periodic payment of principal and interest with various maturities from June 1997 through July 2009. The 7.50% mortgage note requires monthly principal and interest payments through October 9, 2005. The 7.357% mortgage note requires quarterly principal and interest payments through March 15, 2009. The 9.65% mortgage note requires monthly principal and interest payments through February 1, 2028. The unsecured notes outstanding as of December 31, 1996 mature in accordance with the following schedule: Amount - -------------------------------------------------------------------------------- (In thousands) 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 8.00%, due December 31, 2000 160 -------- Total unsecured notes $387,160 ======== Baltimore Gas and Electric Company and Subsidiaries 50 Long-Term Debt of Other Diversified Businesses Long-term debt of other diversified businesses includes a $50 million unsecured revolving credit agreement of Comfort Link which matures September 26, 2001. Loans may be obtained at various rates for terms up to nine months. A facility fee is paid on the total amount of the commitment. At December 31, 1996, $12 million was outstanding under this agreement. Weighted Average Interest Rates for Variable Rate Debt The weighted average interest rates for variable rate debt were as follows: Year ended December 31, 1996 1995 - -------------------------------------------------------------------------------- BGE Floating rate series mortgage bonds 5.87% 6.30% Remarketed floating rate series mortgage bonds 5.63 -- Pollution control loan 3.49 3.79 Port facilities loan 3.59 4.06 Adjustable rate pollution control loan 3.90 3.75 Economic development loan 3.57 4.01 Constellation Companies Loans under credit agreements 6.08 6.74 Mortgage and construction loans and other collateralized notes 8.33 8.99 Other Diversified Businesses Loans under credit agreements 6.13 -- 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: Diversified Year BGE Businesses - -------------------------------------------------------------------------------- (In thousands) 1997 $ 89,848 $107,924 1998 93,578 165,370 1999 247,347 186,339 2000 253,658 97,803 2001 247,183 31,897 As of December 31, 1996, BGE had $195 million of debt with provisions that allow lenders the option to request BGE to repay the debt at certain times prior to maturity. In the event such options are exercised, BGE intends to refinance such debt on a long-term basis through the issuance of medium term notes or using revolving credit agreements. - -------------------------------------------------------------------------------- Note 10. Redeemable Preference Stock The 7.80%, 1989 Series is subject to mandatory redemption in full at par on July 1, 1997. 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 at December 31, 1996 for all series of redeemable preference stock are as follows: Year - -------------------------------------------------------------------------------- (In thousands) 1997 $ 83,000 1998 23,000 1999 23,000 2000 10,000 2001 10,000 Thereafter 68,500 -------- Total aggregate redemption requirements $217,500 ======== With regard to payment of dividends or assets available in the event of liquidation, all issues of preference stock, whether subject to mandatory redemption or not, rank equally; and all preference stock ranks prior to common stock. Baltimore Gas and Electric Company and Subsidiaries 51 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 $11.6 million, $12.2 million, and $12.7 million for the years ended 1996, 1995, and 1994, respectively. The future minimum lease payments at December 31, 1996 for long-term noncancelable operating leases are as follows: Year - -------------------------------------------------------------------------------- (In thousands) 1997 $ 4,899 1998 4,095 1999 2,072 2000 1,893 2001 1,450 Thereafter 2,725 ------- Total minimum lease payments $17,134 ======= 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 19 years, with options to renew. The net book value of property under operating leases was $177.3 million at December 31, 1996. The future minimum rentals to be received under operating leases in effect at December 31, 1996 are as follows: Year - -------------------------------------------------------------------------------- (In thousands) 1997 $ 15,433 1998 14,073 1999 13,146 2000 12,671 2001 11,704 Thereafter 61,735 -------- Total minimum rentals $128,762 ======== - -------------------------------------------------------------------------------- Note 12. Commitments, Guarantees, and Contingencies Commitments BGE has made substantial commitments in connection with its construction program for 1997 and subsequent years. In addition, BGE has entered into three long-term contracts for the purchase of electric generating capacity and energy. The contracts expire in 2001, 2013, and 2023. Total payments under these contracts were $64.1, $68.4, and $69.4 million during 1996, 1995, and 1994, respectively. At December 31, 1996, the estimated future payments for capacity and energy that BGE is obligated to buy under these contracts are as follows: Year - -------------------------------------------------------------------------------- (In thousands) 1997 $ 61,669 1998 78,075 1999 91,938 2000 92,039 2001 62,978 Thereafter 805,110 ---------- Total estimated future payments for capacity and energy under long-term contracts $1,191,809 ========== 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, 1996, the total amount of investment requirements committed to by the Constellation Companies is $56 million. In December, 1994, BGE and HP&S entered into agreements with a financial institution whereby BGE and HP&S 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 HP&S have limited recourse on the receivables and have recorded a reserve for credit losses. At December 31, 1996, BGE and HP&S had sold $35 million and $47 million of receivables, respectively, under these agreements. Guarantees BGE has agreed to guarantee two-thirds of certain indebtedness of Safe Harbor Water Power Corporation. The total amount of indebtedness that can be guaranteed is $50 million, of which $33 million represents BGE's potential share of the guarantee. As of December 31, 1996, outstanding indebtedness of Safe Harbor Water Power Corporation was $32 million, of which $21 million is guaranteed by BGE. BGE has also agreed to guarantee up to $20 million of obligations and indebtedness of Constellation Energy Source, Inc. (formerly named BNG, Inc.) As of December 31, 1996, there were no outstanding obligations under this guarantee. BGE assesses that the risk of material loss on the loans guaranteed is minimal. As of December 31, 1996, the total outstanding loans and letters of credit of certain power generation and real estate projects guaranteed by the Constellation Companies were $54 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. Pending Merger With Potomac Electric Power Company BGE, Potomac Electric Power Company (PEPCO), and Constellation Energy Corporation (formerly named "RH Acquisition Corp.") (CEC), have entered into an Agreement and Plan of Merger, dated as of September 22, 1995 (the Merger Agreement). CEC was formed to accomplish the merger and its outstanding capital stock is owned 50% by BGE and 50% by PEPCO. The Merger Agreement provides for a strategic business combination that will be accomplished by merging both BGE and PEPCO into CEC (the Merger). The Merger, which was unanimously approved by the Boards of Directors of BGE and PEPCO and approved by the shareholders of both companies, is expected to close during 1997 after all other conditions to the consummation of the Merger, including obtaining applicable regulatory approvals (described below), are met or waived. In connection with the Merger, BGE common shareholders will receive one share of CEC common stock for each BGE share and PEPCO common shareholders will receive 0.997 of a share of CEC common stock for each PEPCO share. Baltimore Gas and Electric Company and Subsidiaries 52 Preliminary estimates by the managements of PEPCO and BGE indicate that the synergies resulting from the combination of their utility operations could generate net cost savings of up to $1.3 billion over a period of 10 years following the Merger. These estimates indicate that about two-thirds of the savings will come from reduced labor costs, with the remaining savings split between nonfuel purchasing and corporate and administrative programs. These savings are net of costs to achieve, presently estimated to be approximately $150 million, and are expected to be allocated among shareholders and customers. This allocation will depend upon the results of regulatory proceedings in the various jurisdictions in which BGE and PEPCO operate their utility businesses (see discussion of the issues raised in regulatory proceedings regarding the allocation and other matters). The analyses employed in order to develop estimates of the potential savings as a result of the Merger were necessarily based upon various assumptions which involve judgments with respect to, among other things, future national and regional economic and competitive conditions, inflation rates, regulatory treatment, weather conditions, financial market conditions, interest rates, future business decisions and other uncertainties, all of which are difficult to predict and many of which are beyond the control of BGE and PEPCO. Accordingly, while BGE believes that such assumptions are reasonable for purposes of the development of estimates of potential savings, there can be no assurance that such assumption will approximate actual experience or that all such savings will be realized. Major regulatory proceedings, together with an indication of the current status of the proceeding, which must be concluded in order to proceed with the merger, are listed below. The Merger Agreement provides that a condition to closing is that no such approvals shall impose terms and conditions that would have, or would be reasonably likely to have, a material adverse effect on the business, operations, properties, assets, condition (financial or otherwise), prospects, or results of operations of the new company. (bullet) Federal Energy Regulatory Commission (FERC) - Hearings have been completed and we are waiting for a decision. The hearings explored the merged company's generation market power, including the appropriate geographic markets, and to consider appropriate remedies if the merged company is found to possess generation market power. Testimony of FERC staff included the suggestion that a significant portion of generation (approximately 2400-3600 megawatts) be divested or transmission capability be upgraded or both due to the perceived market power of the merged company in both the wholesale and retail markets. (bullet) Maryland Public Service Commission (Maryland Commission) - Hearings have been completed and we are waiting for a decision. Since the Report on Form 10-Q for the third quarter 1996 was filed, rebuttal and surrebuttal testimony has been filed. Office of People's Counsel (the advocates for residential customers) recommended that the Maryland Commission not approve the Merger until the Applicants demonstrate that Maryland customers will not be harmed by potential restrictions on competition due to the market power of the new company. If, however, the Maryland Commission decides to approve the Merger, People's Counsel continues to recommend rate decreases. Due to the use of a different test period, the amounts are somewhat different than reported in the second quarter Report on Form 10-Q. Based on a test period proposed by People's Counsel in recent testimony, they recommend a pre-merger rate reduction of approximately $108.3 million ($84.7 million to BGE customers and $23.6 million to PEPCO customers) with Merger savings being reflected in further reduced rates of approximately $65 million ($45 million to BGE customers and $20 million to PEPCO customers) contemporaneously with the date of the Merger. A number of other recommendations are also included in People's Counsel testimony. The Maryland Energy Administration (MEA) continues to recommend that the Maryland Commission adopt an alternative regulatory plan and also asks that rates be examined. Maryland Commission Staff testimony also utilizes the new test period. Based on the new test period Maryland Commission Staff recommends an immediate decrease of $63.6 million (BGE's rates reduced by $54.3 million and PEPCO's by $9.3 million) at the time of the Merger. Maryland Commission Staff's surrebuttal testimony also recommends that CEC be required to make a rate filing 15 months after the Merger becomes effective. (bullet) District of Columbia Public Service Commission - Hearings began February 18, 1997. Testimony was filed by the parties in September 1996. The D.C. Office of People's Counsel (the advocates for residential customers) opposes the Merger based on its contention that BGE and PEPCO have not proved that the Merger is in the public interest. Testimony of the D.C. People's Counsel also provides that should the Merger be approved, an immediate rate reduction of $44.2 million be imposed at the time of the Merger, followed by a 5-year moratorium on rate increases. Further, testimony of D.C. People's Counsel advocates divestiture of all nonutility affiliate companies, exclusion of BGE's Calvert Cliffs Nuclear Plant from production plant assigned to D.C., and a 5-year $23.37 million per year economic development program. GSA, a major D.C. customer, requests that any approval should be coupled with an imposition of retail competition access for ratepayers such as GSA, a 25-year amortization of costs to achieve the Merger, and elimination of Calvert Cliffs from the generating mix. In addition to these matters, D.C. People's Counsel, an intervenor, Washington Gas Light Company, and the D.C. Corporation Counsel have questioned the interpretation by BGE and PEPCO that a D.C. statute known as the Antimerger Law is inapplicable to this transaction. Should such statute be deemed to be applicable, authorization of the Merger by Congress would be required. Allegations also were made that BGE and PEPCO should have received Congressional approval for their owning 50% of the shell company, CEC, prior to consummation of the Merger. The reasons for the Merger, the terms and conditions contained in the Merger Agreement, the regulatory approvals required prior to closing the Merger, and other matters concerning the Merger, PEPCO, and CEC are discussed in more detail in the Registration Statement on Form S-4 (Registration No. 33-64799). 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 $90 million. BGE is currently unable to predict the cost of compliance with the additional requirements at other BGE facilities. Baltimore Gas and Electric Company and Subsidiaries 53 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. 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 $7 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. In late December 1996, the Maryland Department of the Environment and BGE signed a consent order that requires BGE to implement remedial action plans addressing contamination at and related to the Spring Gardens site. The specific remedial actions for this site will be developed in the future. BGE has recognized estimated environmental costs at all former gas manufacturing plant sites (based on remedial action options) which are considered probable totaling $50 million in nominal dollars. These costs, net of accumulated amortization, have been deferred as a regulatory asset (see Note 5). Accounting rules also require BGE to disclose additional costs deemed by BGE to be less likely than probable costs, but still "reasonably possible" of being incurred at these sites. Because of the results of recent studies at these sites, it is reasonably possible that these additional costs could exceed the amount recognized by approximately $48 million in nominal dollars ($11 million in current dollars, plus the impact of inflation at 3.1% over a period of up to 60 years). 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 $6.02 million in any one year. For physical damage to Calvert Cliffs, BGE has $2.75 billion of property insurance from industry mutual insurance companies. 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 an 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 accidents at any insured plants cause a shortfall of funds at the industry mutuals, BGE and all policyholders could be assessed, with BGE's share being up to $35.1 million. Recoverability of Electric Fuel Costs By statute, actual electric fuel costs are recoverable so long as the Maryland Commission finds that BGE demonstrates that, among other things, it has maintained the productive capacity of its generating plants at a reasonable level. The Maryland Commission 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 Maryland Commission authorized the establishment of a 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 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 Maryland Commission. 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 GUPP. The resultant case before the Maryland Commission 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 the Maryland People's Counsel (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. On January 23, 1995, the Hearing Examiner issued his decision in the 1987 fuel rate proceeding and found that the Company had met the GUPP standard which establishes a presumption that BGE had operated the plant at a reasonably productive capacity level. However, the Order found that the presumption of reasonableness would be overcome by a showing of mismanagement and that such a showing was made with respect to the environmental qualifications outage time. The Hearing Examiner had mitigated the disallowance of replacement energy costs due to the fact the GUPP standard was met. The Hearing Examiner's Order was appealed to the Maryland Commission by both BGE and People's Counsel. The Maryland Commission upheld the Hearing Examiner's findings with respect to the environmental Baltimore Gas and Electric Company and Subsidiaries 54 qualification related outage time, but disagreed with certain methodologies applied by the Hearing Examiner. The impact of the Maryland Commission's decision on the Company's 1996 earnings was approximately $4.5 million, the amount previously estimated by the Company. People's Counsel has filed a motion for rehearing. In May 1989, BGE filed its fuel rate case in which 1988 performance was examined. BGE met the system-wide and nuclear plant performance targets in 1988. People's Counsel alleged 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 Maryland Commission 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 May 4, 1991, remained out of service for the remainder of 1989, 1990, and the first part of 1991 to repair the pressurizer, perform maintenance and modification work, and complete the refueling. The replacement energy costs associated with these extended outages for both units at Calvert Cliffs, concluding with the return to service of Unit 2, are estimated to be $458 million. In a December 1990 Order issued by the Maryland Commission in a BGE base rate proceeding, the Maryland Commission found that certain operations and maintenance expenses incurred at Calvert Cliffs during the test year should not be recovered from ratepayers. The Maryland Commission 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 Maryland 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 energy costs associated with the outages at Calvert Cliffs. The Maryland Commission 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 Maryland Commission's statement regarding no binding effect, BGE recognizes that the views expressed by the Maryland Commission made 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. In December 1996, BGE entered into a settlement agreement with People's Counsel and the Maryland Commission Staff proposing a resolution to these fuel rate proceedings. BGE agreed that ratepayers will not fund a total of $118 million of electric replacement energy costs associated with the extended outages. This represents $83 million in addition to the $35 million reserve for possible disallowance of replacement energy costs recorded in 1990. Therefore, in December 1996, BGE increased the provision for the disallowance of such costs by $83 million. Additionally, in 1996, BGE wrote off $5.6 million of accrued carrying charges related to the deferred fuel balances. The remainder of the replacement energy costs associated with the extended outage has already been recovered from customers through the fuel rate. California Power Purchase Agreements The Constellation Companies have ownership interests in 16 projects that sell electricity in California under "Interim Standard Offer No. 4" power purchase agreements. Under these agreements, the projects supply electricity to utilities at a fixed rate for capacity and energy the first 10 years of the agreements, and a fixed rate for capacity plus a variable rate for energy based on the utilities' avoided cost for the remaining term of the agreements. Avoided cost generally is the cost of a utility's lowest-cost next-available source of generation to service the demands on its system. From 1996 through 2000, the 10-year periods for fixed energy rates expire for these projects and they will begin supplying electricity at variable rates. At current avoided cost levels, the Constellation Companies would experience reduced earnings or incur losses associated with these projects when they begin supplying electricity at variable rates. Eight projects begin supplying electricity at variable rates in 1997 and 1998. The projects that make the highest revenues will begin supplying electricity at variable rates in 1999 and 2000. As a result, we do not expect the Constellation Companies to experience significantly lower earnings or losses on these projects before 2000. Constellation is pursuing alternatives for these power generation projects including repowering the projects to reduce operating costs, changing fuels to reduce operating costs, renegotiating the power purchase agreements to improve the terms, restructuring financings to improve the financing terms, and selling its ownership interests in the projects. The Company cannot estimate the financial impact of the switch from fixed to variable rates on the Constellation Companies or on BGE, but the impact could be material. Constellation Real Estate Management will consider market demand, interest rates, the availability of financing, and the strength of the economy in general when making decisions about real estate investments. We believe until the economy shows sustained growth and there is more demand for new development, real estate values will not improve much. If we were to sell our real estate projects in the current market, we would have losses, although the amount of the losses is hard to predict. Management's current real estate strategy is to hold each real estate project until we can realize a reasonable value for it. Management evaluates strategies for all its businesses, including real estate, on an ongoing basis.* Competing demands for our financial resources, changes in the utility industry, and the proposed merger with Potomac Electric Power Company, are factors we will consider when we evaluate all diversified business strategies so we use capital and other resources effectively. Depending on market conditions in the future, we could also have losses on any future sales. Applicable accounting rules would require a writedown of a real estate investment to market value in either of two cases. The first is if we change our intent about a project from an intent to hold to an intent to sell and the market value of that project is below book value. The second is if the expected cash flow from the project is less than the investment in the project. * In the first quarter of 1997, we wrote down the investment in one of our projects to market value because we changed our intent about that project. The write-down is described in detail in the front of this report under The Constellation Companies -- Power Generation, Real Estate, and Financial Investments on page 15. Baltimore Gas and Electric Company and Subsidiaries 55 Note 13. Fair Value of Financial Instruments The following table presents the carrying amounts and fair values of financial instruments included in the Consolidated Balance Sheets.
At December 31, 1996 1995 - ----------------------------------------------------------------------------------------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value (In thousands) Cash and cash equivalents $ 66,708 $ 66,708 $ 23,443 $ 23,443 Net accounts receivable 419,479 419,479 400,005 400,005 Other current assets 74,964 74,964 54,070 54,070 Investments and other assets for which it is: Practicable to estimate fair value 184,487 185,679 149,645 150,170 Not practicable to estimate fair value 62,162 -- 73,042 -- Short-term borrowings 333,185 333,185 279,305 279,305 Current portions of long-term debt and preference stock 280,772 280,772 146,969 146,969 Accounts payable 172,889 172,889 177,092 177,092 Other current liabilities 194,065 194,065 193,992 193,992 Long-term debt 2,758,769 2,767,721 2,598,254 2,694,858 Redeemable preference stock 134,500 141,621 242,000 254,809
Financial instruments included in other current assets include trading securities and miscellaneous loans receivable of the Constellation Companies. Financial instruments included in other current liabilities represent total current liabilities from the Consolidated Balance Sheets excluding short-term borrowings, current portions of long-term debt and preference stock, accounts payable, and 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 Consolidated Balance Sheets, and the nuclear decommissioning trust fund. The fair value of investments and other assets is based on quoted market prices where available. It was not practicable to estimate the fair value of the Constellation Companies' investments in several financial partnerships which invest in nonpublic debt and equity securities, investments in several partnerships which own solar powered energy production facilities, and in an investment in a company involved in the development of international power projects because the timing and magnitude of cash flows from these investments are difficult to predict. These investments are carried at their original cost in the Consolidated Balance Sheets. The investments in financial partnerships totaled $48 million and $50 million at December 31, 1996 and 1995, respectively, representing ownership interests up to 10%. The aggregate assets of these partnerships totaled $6.1 billion at December 31, 1995. The investments in solar powered energy production facility partnerships totaled $11 million and $22 million at December 31, 1996 and 1995, respectively, representing ownership interests up to 12%. The aggregate assets of these partnerships totaled $35 million at December 31, 1995. 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 on outstanding indebtedness totaling $21 million and $47 million, respectively, at December 31, 1996 and $22 million and $35 million, respectively, at December 31, 1995 for which it is not practicable to determine fair value. It is not anticipated that these loan guarantees will need to be funded. Baltimore Gas and Electric Company and Subsidiaries 56 Note 14. Quarterly Financial Data (Unaudited) The following data are unaudited but, in the opinion of Management, include all adjustments necessary for a fair presentation. BGE's utility business is seasonal in nature with the peak sales periods generally occurring during the summer and winter months. Accordingly, comparisons among quarters of a year may not be indicative of overall trends and changes in operations.
Quarter Ended ------------------------------------------------------------- Year Ended March 31 June 30 September 30 December 31 December 31 - ------------------------------------------------------------------------------------------------------------------------- (In thousands, except per-share amounts) 1996 Revenues $861,330 $731,707 $825,960 $734,250 $3,153,247 Income from operations 201,315 148,637 275,667 43,846 669,465 Net income 100,781 64,553 146,482 (992) 310,824 Earnings applicable to common stock 91,118 52,448 137,862 (9,140) 272,288 Earnings per share of common stock 0.62 0.36 .93 (.06) 1.85 ============================================================================= 1995 Revenues $717,806 $642,500 $848,781 $725,712 $2,934,799 Income from operations 148,222 120,920 299,744 126,806 695,692 Net income 70,854 50,889 163,335 52,929 338,007 Earnings applicable to common stock 60,902 40,937 153,104 42,486 297,429 Earnings per share of common stock 0.41 0.28 1.04 0.29 2.02 =============================================================================
1996 Results for the second quarter reflect: (bullet) the $4.5 million after-tax write-off of disallowed replacement energy costs (see Note 1). (bullet) the $14.6 million after-tax gain on the sale by a Constellation partnership of a power purchase agreement (see Note 3). (bullet) the $7.0 million and $3.0 million after-tax write-offs by the Constellation Companies of the investment in two geothermal wholesale power generating plants and the development costs of a proposed coal-fired power project, respectively (see Note 3). Results for the third quarter reflect the $6.2 million after-tax write-off by the Constellation Companies of a portion of a solar power project investment (see Note 3). Results for the fourth quarter reflect the $57.6 million after-tax write-off of disallowed replacement energy costs (see Note 1). 1995 Results for the third quarter reflect the $9.7 million after-tax write-off of certain Perryman costs (see Note 1). Baltimore Gas and Electric Company and Subsidiaries 57 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Directors --------- The following are the Directors of BGE on the date of this report. They were each elected at BGE's 1996 Annual Meeting of Shareholders. We expect the pending Merger with PEPCO to close prior to the expiration of their terms of office. Should the Merger be delayed, these terms would expire at BGE's 1997 Annual Meeting of Shareholders which would be held during the period of August 18th through September 16th. H. FURLONG BALDWIN, age 65, currently serves as Chairman of the Board and Chief Executive Officer of Mercantile Bankshares Corporation (a bank holding company), positions he has held since 1984 and 1976, respectively, and as Chairman of the Board and Chief Executive Officer of Mercantile-Safe Deposit and Trust Company, positions he attained in 1976. Mr. Baldwin also serves as a director of GRC International, Inc., USF&G Corporation, Conrail, Inc., Offitbank, Wills Group, and Constellation Holdings, Inc. Mr. Baldwin has been a director of the Company since 1988 and is a member of the Executive Committee and is the Chairman of the Long Range Strategy Committee. BEVERLY B. BYRON, age 64, served for seven successive terms as a Congresswoman to the United States House of Representatives from 1978 to 1992. She is a director of McDonnell Douglas Corp., Farmers & Mechanics Bank, and UNC Incorporated. Mrs. Byron has been a director of the Company since 1993 and is a member of the Audit Committee, the Committee on Nuclear Power and is the Chairwoman of the Committee on Workplace Diversity. J. OWEN COLE, age 67, currently serves as Chairman of the Board of Blue Cross and Blue Shield of Maryland, a position he has held since January 1995. In addition, Mr. Cole serves as Chairman of the Trust Committee of the Board of Directors of both First Maryland Bancorp (a bank holding company) and The First National Bank of Maryland, positions he has held since 1994. From 1988 to 1994, Mr. Cole served as Chairman of the Executive Committee of the Board of Directors of both First Maryland Bancorp and The First National Bank of Maryland. Mr. Cole has been a director of the Company since 1977 and is the Chairman of the Audit Committee and a member of the Committee on Management. DAN A. COLUSSY, age 65, currently serves as Chairman of the Board, President and Chief Executive Officer of UNC Incorporated (aviation services). He was elected Chief Executive Officer in 1984, Chairman of the Board in 1989, served as President from 1984 to September 1994, and currently serves as President since October 1995. Mr. Colussy also serves as Chairman-Elect and director of Blue Cross and Blue Shield of Maryland. He has been a director of the Company since 1992 and is a member of the Committee on Management and the Chairman of the Committee on Nuclear Power. EDWARD A. CROOKE, age 58, currently serves as President and Chief Operating Officer of the Company. Mr. Crooke has been President of the Company since 1988 and Chief Operating Officer since 1992. He is also Chairman of the Board of BGE Home Products & Services, Inc., and Chairman of the Board and Chief Executive Officer of Constellation Energy Source, Inc. (formerly named BNG, Inc.), positions he attained in 1994. In addition, Mr. Crooke is Chairman of the Board of BGE Energy Projects & Services, Inc., a position he attained in November 1995 and is Chairman of the Board of Constellation Holdings, Inc., a position he attained in January 1996. Mr. Crooke serves as a director of First Maryland Bancorp, The First National Bank of Maryland, AEGIS Insurance Services, Associated Electric & Gas Insurance Services, Limited, and Baltimore Equitable Society. Mr. Crooke has been a director of the Company since 1988 and is a member of the Executive Committee. JAMES R. CURTISS, age 43, currently is a partner in the law firm of Winston & Strawn, a position he attained in 1993. From 1988 to 1993, he served as a Commissioner of the United States Nuclear Regulatory Commission. Mr. Curtiss is also a director of Cameco Corporation. He has been a director of the Company since 1994 and is a member of the Committee on Nuclear Power and the Committee on Workplace Diversity. 58 JEROME W. GECKLE, age 67, was Chairman of the Board of PHH Corporation (vehicle, relocation, and management services) from 1979 to 1989. Now retired, Mr. Geckle serves as a director of First Maryland Bancorp, The First National Bank of Maryland, and Constellation Holdings, Inc. Mr. Geckle has been a director of the Company since 1980 and is the Chairman of the Committee on Management and a member of the Long Range Strategy Committee. DR. FREEMAN A. HRABOWSKI, III, age 46, currently serves as the President of the University of Maryland Baltimore County, a position he attained in 1993. Previously, he served as Interim President from 1992 to 1993 and Executive Vice President from 1990 to 1992. Dr. Hrabowski is also a director of the Baltimore Equitable Society, Mercantile Bankshares Corporation, and UNC Incorporated. He has served as a director of the Company since 1994 and is a member of the Audit and Executive Committees and the Committee on Workplace Diversity. NANCY LAMPTON, age 54, currently serves as Chairman and Chief Executive Officer of American Life and Accident Insurance Company of Kentucky, a position she attained in 1971. Ms. Lampton is also a director of Bank One Kentucky, Brinly-Hardy, and Duff & Phelps Utility Income Fund, Inc. She has served as a director of the Company since 1994 and is a member of the Long Range Strategy Committee and the Committee on Workplace Diversity. GEORGE V. MCGOWAN, age 69, served as Chairman of the Board and Chief Executive Officer of the Company and Chairman of the Board of Constellation Holdings, Inc., from 1988 to 1992. Mr. McGowan is a director of The Baltimore Life Insurance Company, Life of Maryland, Inc., McCormick & Company, Inc., NationsBank, N.A., Organization Resources Counselors, Inc., and UNC Incorporated. Mr. McGowan has been a director of the Company since 1980 and is the Chairman of the Executive Committee and a member of the Committee on Nuclear Power. CHRISTIAN H. POINDEXTER, age 58, currently serves as Chairman of the Board and Chief Executive Officer of the Company, positions he attained in 1993, after serving as Vice Chairman of the Board, a position he held since 1989. Mr. Poindexter is also a director of BGE Home Products & Services, Inc., a position he attained in 1994, and is a director of BGE Energy Projects & Services, Inc., a position he attained in November 1995. Currently, Mr. Poindexter serves as a director of Constellation Holdings, Inc., after serving as Chairman of the Board from 1993 to January 1996. In addition, Mr. Poindexter serves as a director of Dome Corporation, Johns Hopkins Medicine Board, Mercantile Bankshares Corporation, Mercantile Mortgage Corporation, and Mercantile-Safe Deposit and Trust Company, Nuclear Electric Insurance Limited, and Nuclear Mutual Limited Insurance Company. Mr. Poindexter has been a director of the Company since 1988 and is a member of the Executive Committee. GEORGE L. RUSSELL, JR., age 67, currently is a partner in the law firm of Piper & Marbury L.L.P., a position he attained in 1986. Mr. Russell is also a director of the Federal Reserve Bank of Richmond. He has been a director of the Company since 1988 and is a member of the Audit and the Executive Committees. MICHAEL D. SULLIVAN, age 57, currently is Chairman of the Board of Golf America Stores, Inc. (golf apparel retailing), a position he attained in October 1996. He is also Chairman of the Board and Chief Executive Officer of Lombardi Research Group, LLC (hair care products), positions he attained in 1995. Mr. Sullivan was Chairman of the Board of Waye Laboratories, Inc. (hair restoration) from January 1995 to June 1995. In addition, Mr. Sullivan was Chief Executive Officer and President, from 1982 to 1994, of Merry-Go-Round Enterprises, Inc. (specialty retailing). That company filed a reorganization petition under Chapter XI of the Federal Bankruptcy law in January 1994, and subsequently announced a bankruptcy liquidation. Mr. Sullivan has been a director of the Company since 1992 and is a member of the Committee on Management and the Long Range Strategy Committee. BOARD OF DIRECTORS COMMITTEES, MEETINGS, AND FEES The Executive Committee of the Board of Directors may exercise most of the powers of the Board of Directors in the management of the business and affairs of the Company in the intervals between meetings of the full Board. The Committee, however, may not declare dividends, authorize the issuance of stock, recommend to shareholders any action requiring shareholders' approval, amend the by-laws, or approve mergers. The Audit Committee of the Board of Directors, comprised of outside directors, recommends an auditing firm to be engaged, discusses the scope of the examination with that firm, and reviews the annual financial 59 statements with the auditing firm and with Management of the Company. Additionally, the Committee meets with the Manager of the Auditing Department of the Company to ensure that an adequate program of internal auditing is being carried out, and invites comments and recommendations from the auditing firm concerning the system of internal controls and accounting procedures. The Audit Committee reports on its activities periodically to the Board of Directors. The Committee on Nuclear Power monitors the performance and safety of the Company's Calvert Cliffs Nuclear Power Plant. The Committee meets periodically, usually on-site at the Calvert Cliffs plant, to confer with Management, senior plant management, and other nuclear oversight personnel. Following each meeting, the Committee reports the results of its observations and findings to the Board of Directors and makes such recommendations as it deems appropriate. The Committee on Management's duties include recommending to the Board of Directors nominees for election as directors and officers and making recommendations concerning remuneration arrangements for directors and officers of the Company. This Committee, which is comprised of outside directors, considers nominees recommended by shareholders; such recommendations should be submitted in writing to the attention of the Corporate Secretary, Baltimore Gas and Electric Company, 39 West Lexington Street, Baltimore, Maryland 21201. The Committee on Workplace Diversity provides an ongoing Board of Directors' perspective of management's progress in achieving employee diversity goals. The Committee provides input to management in setting goals and developing strategies to increase goal attainment, provides oversight on implementation of strategies, and evaluates results. The Committee on Workplace Diversity reports on its activities periodically to the Board of Directors. The Long Range Strategy Committee provides an oversight role in the development of the Company's long range strategic goals. The Committee meets periodically to review the continued appropriateness of these goals and to approve presentations to the Board regarding the implementation of significant strategic initiatives. This Committee also reviews major regulatory, environmental and public policy issues as well as technology advances which may impact Company operations. The Long Range Strategy Committee reports on its activities periodically to the Board of Directors. The Board of Directors met nine times during 1996 for regularly scheduled meetings. The Committee on Management and the Audit Committee each met four times, the Committee on Nuclear Power met three times, and the Committee on Workplace Diversity and the Executive Committee each met two times. Each of the directors attended 75% or more of the total number of meetings of the Board and of any committees on which the director served. Each director, who is not an officer or employee of the Company or its subsidiaries, receives a fee of $1,000 for each regular, committee, or special meeting of the Board attended and a retainer fee of $18,000 per year, payable quarterly. Each committee chairman receives an additional annual retainer fee of $3,000 per year, payable quarterly. Each director may be reimbursed for reasonable travel expenses incidental to attendance at meetings. Each director who is not an officer or employee may elect to defer receipt of any portion of the fees earned. In addition, the Company maintains a director retirement plan. Under this plan, non-employee directors with at least five years of service receive an annual retirement benefit for life equal to the annual Board retainer in effect at the time of the director's retirement from the Board. Benefit payments begin at the director's date of retirement or at age 65, whichever is later. The Company also provides an automobile to Mr. McGowan, a director who retired on December 31, 1992 as Chairman of the Board and Chief Executive Officer of the Company and who continues to participate in civic and community activities on behalf of the Company. The approximate yearly cost to the Company is $7,908. Executive Officers ------------------ Executive Officers of BGE at the date of this report are:
OTHER OFFICES OR POSITIONS NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS ---- --- -------------- --------------------------- Christian H. Poindexter 58 Chairman of the Board (A) Vice Chairman of the Board (Since January 1, 1993)
60
OTHER OFFICES OR POSITIONS NAME AGE PRESENT OFFICE HELD DURING PAST FIVE YEARS ---- --- -------------- --------------------------- Edward A. Crooke 58 Chairman of the Board - President, Utility Operations Subsidiaries and President (B) (Since January 1, 1996) Bruce M. Ambler 57 President and Chief Executive Officer Constellation Holdings, Inc. (Since August 1, 1989) George C. Creel 63 Executive Vice President Senior Vice President, Generation and Acting Chief Operating Vice President, Nuclear Energy Officer (Since January 1, 1996) Charles W. Shivery 51 President Vice President BGE Corp. and President Finance and Accounting, and Chief Executive Chief Financial Officer and Officer Constellation Power Secretary Source, Inc. Vice President and Treasurer, (Since February 25, 1997) Corporate Finance Group Robert E. Denton 54 Senior Vice President Vice President, Nuclear Energy Generation Plant General Manager, Calvert (Since January 1, 1996) Cliffs Nuclear Power Plant Thomas F. Brady 47 Vice President Vice President, Customer Service Customer Service and and Accounting Distribution Vice President, Accounting and (Since July 1, 1993) Economics David A. Brune 56 Vice President General Counsel Finance and Accounting, Chief Financial Officer and Secretary (Since February 25, 1997) Charles H. Cruse 52 Vice President Plant General Manager, Calvert Nuclear Energy Cliffs Nuclear Power Plant (Since January 1, 1996) Manager, Nuclear Engineering Carserlo Doyle 54 Vice President Manager, Telecommunications Electric Interconnection Principal Engineer -- Electric and Transmission Interconnection (Since January 1, 1994) Jon M. Files 61 Vice President Management Services (Since September 1, 1981) Frank O. Heintz 52 Vice President Executive Director, LDC Caucus -- Gas American Gas Association (Since January 1, 1997) Chairman, Maryland Public Service Commission Sharon S. Hostetter 52 Vice President Manager, Marketing Marketing and Sales Division Manager, Resource (Since November 1, 1995) Application and Customer Development Group, Rochester Gas and Electric Corporation Ronald W. Lowman 52 Vice President Manager, Fossil Engineering Fossil Energy Manager, Fossil Engineering (Since January 1, 1993) Services G. Dowell Schwartz, Jr. 60 Vice President General Services (Since April 1, 1990) Joseph A. Tiernan 58 Vice President Vice President, Corporate Corporate Affairs Administration (Since February 1, 1993) Stephen F. Wood 44 President and Vice President, Marketing and Sales Chief Executive Officer Manager, Major Customer Projects BGE Energy Projects & Manager, System Engineering Services, Inc. and Construction (Since November 1, 1995) Manager, Distribution Engineering Vice President (Since February 16, 1996)
61 - ----------- (A) Chief Executive Officer, Director, and member of the Executive Committee. (B) Chief Operating Officer, Director, and member of the Executive Committee. 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 director or officer and any other person pursuant to which the director or officer was selected. ITEM 11. EXECUTIVE COMPENSATION The summary compensation table below (together with important explanatory notes on the next page) provides information about salary and other compensation. Following the summary compensation table are tables about long-term incentive plan awards and pension benefits, a performance graph that compares BGE common stockholder return to both the S&P 500 Index and the Dow Jones Electric Utilities Index, and a report by the Committee on Management about executive compensation. SUMMARY COMPENSATION TABLE
LONG-TERM ANNUAL COMPENSATION COMPENSATION ------------------- ------------ ALL OTHER COMPENSATION (INCLUDES ONE- TIME PAYMENT FOR YEARS RESTRICTED LTIP 1988-1996; STOCK AWARD PAYOUT SEE NOTE 3 NAME AND PRINCIPAL POSITION FISCAL (SEE NOTE 1 (SEE NOTE 2 ON NEXT @ 12/31/96 YEAR SALARY BONUS ON NEXT PAGE) ON NEXT PAGE) PAGE) --------------------------- ------ ------ ----- ------------- ------------- ------------ Christian H. Poindexter 1996 $ 567,300 $212,500 -0- $ 181,500 $324,799 Chairman of the Board & Chief 1995 $ 537,233 $247,400* -0- N/A $ 31,611 Executive Officer 1994 $ 498,533 $163,000 -0- N/A $ 26,436 Edward A. Crooke 1996 $ 403,400 $150,000 -0- $ 118,800 $252,504 President & Chief Operating 1995 $ 400,567 $184,200* -0- N/A $ 25,217 Officer, Chairman of the Board of 1994 $ 385,067 $125,000 -0- N/A $ 19,089 all non-utility subsidiaries George C. Creel 1996 $ 316,600 $118,000 -0- $ 72,600 $138,842 Executive Vice President & Acting 1995 $ 265,600 $ 72,900 -0- N/A $ 17,292 Chief Operating Officer 1994 $ 248,867 $ 55,000 -0- N/A $ 11,754 Bruce M. Ambler 1996 $ 315,100 $120,000 -0- $ 180,000 $117,101 President & Chief Executive Officer 1995 $ 298,933 $108,600 -0- N/A $ 17,033 of Constellation Holdings, Inc. 1994 $ 280,133 $ 69,000 -0- N/A $ 11,443 Robert E. Denton 1996 $ 230,567 $ 75,100 -0- $ 38,500 $ 70,899 Senior Vice President -- Generation 1995 $ 196,933 $ 55,000 -0- N/A $ 10,785 1994 $ 172,467 $ 36,000 -0- N/A $ 7,090
- ----------- * These amounts include a $ 100,000 bonus for Mr. Poindexter and a $ 75,000 bonus for Mr. Crooke for their work in connection with the Merger. 62 NOTES TO SUMMARY COMPENSATION TABLE (1) At December 31, 1996, Mr. Poindexter held 26,635 shares of performance-based Restricted Stock with a value of $712,486, Mr. Crooke held 19,085 shares of performance-based Restricted Stock with a value of $510,524, Mr. Creel held 17,224 shares of performance-based Restricted Stock with a value of $460,742, Mr. Ambler held 16,401 shares of performance-based Restricted Stock with a value of $438,727, and Mr. Denton held 12,952 shares of performance-based Restricted Stock with a value of $346,466. Dividends on performance-based Restricted Stock Awards are accumulated during the performance period, reinvested in BGE shares, and reflected in the preceding shares and values. Additional awards were granted effective February 12, 1997 as described below in the Long-Term Incentive Plan Table. (2) The amounts in the LTIP PAYOUT column were paid for performance during the 1994-1996 period. (3) The amounts in the ALL OTHER COMPENSATION COLUMN include the Company match under the Company's savings plans; the interest on the cumulative corporate funds used to pay annual premiums on policies providing split-dollar life insurance benefits (calculated at the Internal Revenue Service's blended rate); and a contribution to a trust securing the executives' supplemental pension benefits. These amounts also include a one-time contribution by BGE to fund a trust that was established in 1996 to secure executives' nonqualified deferred compensation plan benefits. The nonqualified deferred compensation plan was put in place in 1988 to permit executives to defer compensation and establish phantom investment accounts equivalent to the compensation being deferred. The amount of the funding is equal to the interest, dividends and capital appreciation recorded in those accounts since 1988. A breakdown of the 1996 amounts in the ALL OTHER COMPENSATION column is shown on the chart below -- notes (a), (b), and (c) under the chart include important background data. Both the chart and the background data are needed to understand the numbers in the ALL OTHER COMPENSATION column.
SUPPLEMENTAL DEFERRED COMPANY MATCH AND PENSION TRUST COMPENSATION TRUST SPLIT DOLLAR AMOUNTS CONTRIBUTION CONTRIBUTION (A) (B) (C) TOTAL -------------------- ------------- ------------------ --------- Christian H. Poindexter...................... $41,541 $53,999 $229,259 $324,799 Edward A. Crooke............................. 33,387 53,999 165,118 252,504 George C. Creel.............................. 24,477 53,999 60,366 138,842 Bruce M. Ambler.............................. 22,442 53,999 40,660 117,101 Robert E. Denton............................. 14,985 53,999 1,915 70,899
- ----------- (a) The Company match and split-dollar amounts shown in column (a) above were the only items included in the ALL OTHER COMPENSATION column for 1995 and 1994. (b) An initial contribution to the trust securing supplemental pension benefits -- shown in column (b) above -- was made during 1996. Therefore, there were no trust contributions included in the ALL OTHER COMPENSATION column for 1995 or 1994. (c) A ONE-TIME contribution was made during 1996 to the trust securing deferred compensation plan benefits equal to the interest, dividends and capital appreciation on plan accounts SINCE 1988. Therefore, there were no trust contributions included in the ALL OTHER COMPENSATION column for 1995 or 1994. 63 LONG-TERM INCENTIVE PLAN TABLE The Committee on Management, effective February 12, 1997, made grants of performance-based restricted shares under the Long-Term Incentive Plan. For each named executive, the grants are subject to both performance and time (3 years) contingencies. For all but Mr. Ambler, performance will be measured by comparing BGE's total shareholder return to the Dow Jones Electric Utilities Index. Both are shown in the performance graph on page 66. A threshold award will be earned if the BGE three-year cumulative total shareholder return percentile rank is at the 50th percentile, progressing to a maximum award for a return at or above the 75th percentile. At the Merger effective date, the shares of restricted BGE stock outstanding will be converted to shares of restricted Constellation Energy Corporation common stock, using the Merger conversion ratio: one share of Constellation Energy Corporation common stock for each share of BGE common stock. After the Merger effective date, the total shareholder return measure will be based upon the return taking into account the growth in common stock value of Constellation Energy Corporation and dividends. For Mr. Ambler, the performance will be measured by comparing BGE's total shareholder return to the Dow Jones Electric Utilities Index and on Constellation Holdings' return on equity over the performance period. Pursuant to the grants, restricted shares were issued equivalent to the number of shares that will be earned if "target" performance (62.5th percentile) is achieved. These restricted shares will be forfeited in whole or part, if performance is below target. Dividends on the restricted shares will be accumulated during the performance period and reinvested in BGE shares. Actual dividends awarded at the end of the performance period will be based upon performance and paid in stock (except that the recipients may elect to have a portion of the shares withheld to satisfy tax withholding requirements). Additional shares, up to the maximum number noted below, will be awarded if performance is above target at the end of the 1997-1999 performance period. Dividend equivalents from the date of the grant will be paid for any additional shares that are awarded.
PERFORMANCE NAME MINIMUM(A) TARGET(A) MAXIMUM(A) PERIOD ---- ---------- --------- ---------- ----------- C.H. Poindexter............................................. 6,500 13,000 19,500 3 years E.A. Crooke................................................. 4,500 9,000 13,500 3 years G.C. Creel.................................................. 4,500 9,000 13,500 3 years B.M. Ambler................................................. 3,500 7,000 10,500 3 years R.E. Denton................................................. 2,500 5,000 7,500 3 years
- ----------- (A) The target number of shares have been issued. If fewer shares are actually earned during the performance period, all or some shares will be forfeited; if additional shares are actually earned during the performance period, additional shares, up to the maximum listed, will be issued. PENSION BENEFITS The following table shows annual pension benefits payable upon normal retirement to executives, including the five individuals named in the Summary Compensation Table. Normal retirement occurs at age 65 for Messrs. Poindexter, Crooke, and Ambler, and at age 62 for all other executives. Pension benefits are computed at 60% of total final average salary plus bonus for Messrs. Poindexter, Crooke, and Ambler, without regard to years of service. Pension benefits are computed at 55% of total final average salary plus bonus for Mr. Creel, who has attained the maximum credited years of service. Pension benefits are computed at 50% of total final average salary plus bonus for Mr. Denton and, when he attains 30 years service in 2000, will be computed at 55%. 64
TOTAL FINAL PERCENTAGE OF FINAL AVERAGE SALARY AND BONUS SALARY AND -------------------------------------------- BONUS 50% 55% 60% - ----------- --- --- --- $ 300,000 $ 150,000 $ 165,000 $ 180,000 325,000 162,500 178,750 195,000 350,000 175,000 192,500 210,000 400,000 200,000 220,000 240,000 425,000 212,500 233,750 255,000 450,000 225,000 247,500 270,000 500,000 250,000 275,000 300,000 550,000 275,000 302,500 330,000 575,000 287,500 316,250 345,000 600,000 300,000 330,000 360,000 650,000 325,000 357,500 390,000 700,000 350,000 385,000 420,000 750,000 375,000 412,500 450,000 775,000 387,500 426,250 465,000 800,000 400,000 440,000 480,000 850,000 425,000 467,500 510,000 900,000 450,000 495,000 540,000 950,000 475,000 522,500 570,000
Salary and bonus are calculated in the same manner shown in the Summary Compensation Table. There is no offset of pension benefits for social security or other amounts. SECURING EXECUTIVE BENEFITS During 1994, the Company implemented a program to secure the supplemental pension benefits for each of the executive officers, including those listed in the Summary Compensation Table. During 1996, the Company implemented a program to secure deferred compensation of executive officers including those listed in the Summary Compensation Table. These programs do not increase the amount of supplemental pension benefits or deferred compensation. In the past, both supplemental pension benefits and deferred compensation were unfunded -- that means no money was set aside on behalf of the executive as he earned the benefit, and the benefits were paid from the Company's general funds when the executive retired. To provide security, accrued supplemental pension benefits and deferred compensation are now being funded through a trust at the time they are earned. An executive officer's accrued benefits in the supplemental pension trust become vested when any of these events occur: retirement eligibility; termination, demotion or loss of benefit eligibility without cause; a change of control of the Company followed within two years by the executive's demotion, termination or loss of benefit eligibility; or reduction of previously accrued benefits. As a result of becoming vested, the executive would be entitled to a payout of the vested amount from the supplemental pension trust upon the later of age 55 or employment termination. An executive's benefits under the deferred compensation plan always are fully vested and are payable at employment termination. Payments to these trusts are included in the Summary Compensation Table in the "All Other Compensation" column. AGREEMENTS RELATING TO THE MERGER In connection with the Merger, Messrs. Poindexter and Crooke each signed an employment agreement dated as of September 22, 1995 with Constellation Energy Corporation. Mr. Poindexter's agreement provides that he will serve as Chief Executive Officer from the time the Merger is completed and that he will become Chairman one year after the Merger is completed. Mr. Crooke's agreement provides that he will serve as Vice Chairman of Constellation Energy Corporation and also as Chairman of all the non-utility subsidiaries. These agreements remain in effect for five years after the Merger is completed. In December 1995, BGE entered into severance agreements with 15 key employees. The agreements become binding on Constellation Energy Corporation at the time the Merger is completed and remain in effect for two years thereafter. The severance agreements provide for the payment of severance benefits to the executive under certain circumstances including, but not limited to, the following (i) upon termination of 65 employment (other than for cause, death, disability or the executive's voluntary termination of employment without "good reason") within the two year period following the time the Merger is completed or (ii) termination of the executive's employment without cause or the executive's voluntary termination following the occurrence of certain events that constitute "good reason" prior to the time the Merger is completed. Four of the 15 key employees who have severance agreements with BGE are retiring when the Merger closes and are entitled to severance benefits. All other key employees who have severance agreements have been offered, and accepted, executive positions with Constellation Energy Corporation and will not be eligible for severance benefits when the Merger closes. If the four retiring employees had been terminated as of December 31, 1996, under circumstances giving rise to an entitlement to benefits thereunder, the aggregate value of such benefits would have been approximately: $750,000 for Mr. Creel, and an aggregate of $2 million for the other executives, none of whom is named in the Summary Compensation Table. PERFORMANCE GRAPH The following graph assumes $100 was invested on December 31, 1991 in Baltimore Gas and Electric Company common stock, S&P 500 Index and Dow Jones Electric Utilities Index. Total return is computed assuming reinvestment of dividends. [Graph appears here--plot points are listed below] Dow Jones Year BGE Electric Utility Index S&P 500 - ---- --- ---------------------- ------- 1991 100 100 100 1992 109 107 108 1993 126 119 118 1994 117 105 120 1995 161 138 165 1996 160 139 203 REPORT OF COMMITTEE ON MANAGEMENT REGARDING EXECUTIVE COMPENSATION The Committee on Management, made up completely of outside Directors, is responsible for executive compensation policies. In addition to establishing policies, the Committee approves all compensation plans and recommends to the Board of Directors specific salary amounts and other compensation awards for individual executives. The Committee designs compensation policies to encourage executives to manage BGE in the best long-term interests of shareholders and to allow BGE to attract and retain executives best suited to lead BGE in a changing industry. 66 The Committee determined that the relevant labor market for executives is the utility industry. Utilities used for comparison in 1996 were electric utilities and combination electric/gas utilities that have annual revenues in the $2-5 billion range, adjusted by using regression analysis to account for BGE's size. These utilities are thought to best represent the portion of the executive labor market in which BGE competes. All of these utilities are included in the Dow Jones Electric Utilities Index shown on the Performance Graph. The Committee's philosophy is that base salary should approximate the middle of that labor market for average performance, and that short-term and long-term incentive awards for superior performance should bring total compensation to approximately the 75th percentile of the labor market. Total compensation is made up of three components: base salary, short-term incentive awards, and long-term incentive awards. As described below, corporate performance is one of the criteria used by the Committee in determining base salary, and it is a key component in determining both short-term and long-term incentive awards. The Committee has retained an outside executive compensation consultant since 1993. He provides information and advice on a regular basis. In addition, internal compensation analysts (certified by the American Compensation Association) use survey data, outside consultants, and other resources to make recommendations to the Committee. Base salary ranges did not change for the named executives in 1996 except Mr. Creel. He was elected Executive Vice President and named acting Chief Operating Officer during 1996 to allow Mr. Crooke time for leading the Merger transition team. Both his salary range and his base salary were increased to reflect these new responsibilities. Salary increases during 1996 for Mr. Poindexter and the other named executives were based upon 1995 corporate performance (consolidated corporate earnings from ongoing operations increased 4.5%, or $.09 per share, in 1995 compared to 1994, and utility earnings from ongoing operations increased 1.6%, or $0.03 per share, in 1995 compared to 1994), and the corporate response to changes in the industry and the regulatory environment. Mr. Poindexter's base salary increase of 5.6% moved him to the middle third of his salary range. Bonus payments to Mr. Poindexter and other executives represent the short-term incentive component of executive compensation. The Committee sets short-term incentive amounts, as well as the mix among base salary, short-term incentive compensation and long-term incentive compensation, to bring total compensation in line with survey data for the relevant labor market. For 1996 short-term incentive awards, the Committee determined that the appropriate measure for earnings was earnings from ongoing operations. This had the effect of eliminating the $.42 per share reduction related to the write-off of $83 million for deferred fuel costs from the extended 1989-1991 outage at BGE's Calvert Cliff's nuclear power plant. In making this decision, the Committee gave weight to the following facts: (a) the $118 million settlement amount (the $83 million written off in 1996 plus the $35 million reserve taken in 1990) is considerably lower than initial demands of People's Counsel ($458 million) and PSC Staff ($200 million), (b) the total maintenance performed during the extended outage resulted in the plant being in excellent operating condition, as evidenced by its good operating history since the end of the extended outage, (c) leadership provided by the executives to the team that handled the litigation and negotiated the settlement. Mr. Poindexter's, Mr. Crooke's, and Mr. Creel's short-term bonuses were based on two factors of equal importance: corporate earnings (an increase of 8.6%, or $.18 per share, in 1996 compared to 1995); and corporate business plan performance in the following areas: customer satisfaction, innovation, and internal business perspectives. Mr. Shivery's short-term incentive bonus was based upon two factors of equal importance: higher consolidated corporate earnings as described above, and achievement of operational targets contained in the finance and accounting division's business plan. Mr. Ambler's bonus was based upon net income from Constellation Holdings ($42.3 million in 1996, an increase of 56.1%, compared to $27.1 million in 1995) weighted at 50%; higher consolidated corporate earnings as described above, weighted at 20%; and operational targets contained in Constellation Holdings' business plan weighted at 30%. Early this year the named executives received cash long-term bonuses for the 1994-1996 performance period. These awards were earned under a cash Long-Term Performance Program for executive officers, including Mr. Poindexter, adopted in 1993. The Program was designed to tie the awards directly to total shareholder return. These awards were the only awards made under the Program. Program objectives for Messrs. Poindexter, Crooke, Creel, and Shivery are based upon BGE total shareholder return during the period 1994-1996 compared to total shareholder return for the other companies included in the Dow Jones Electric Utilities Index (one of the indices used in the Performance Graph). Performance (61st percentile) 67 exceeded the target of (60th percentile) and produced awards that were slightly above target. For Mr. Ambler, the performance objectives measured improvement in Constellation Holdings' net income over the same three year period. He received a maximum award based upon an improvement in net income of 255%. Awards to the named executives are disclosed in the column of the Summary Compensation Table titled LONG-TERM COMPENSATION -- LTIP PAYOUT. The current Long-Term Incentive Plan was approved by the shareholders at the 1995 Annual Meeting of Shareholders and will be in effect until 2005. The Committee specifically included numerous features in the Long-Term Incentive Plan to allow various types of awards keyed to corporate performance, including performance shares and restricted stock subject to performance-based contingencies. Awards in 1995 and 1996 of performance-based restricted stock were granted under the Plan to the named executives and are included in footnote 1 to the Summary Compensation Table on page 63. Awards of performance-based restricted stock granted in 1997 to the named executives are shown on the Long-Term Incentive Plan table on page 64. The awards are subject to forfeiture if corporate performance criteria are not satisfied or if the executive's employment terminates during the applicable three year performance periods. The corporate performance criteria for all named executives except Mr. Ambler for each period is measured by total shareholder return over the performance period compared to total shareholder return for the other companies included in the Dow Jones Electric Utilities Index (one of the indices used in the Performance Graph) and are as follows: a threshold award at the 50th percentile, progressing to a maximum payout if percentile rank for total shareholder return exceeds the 75th percentile. For Mr. Ambler, the performance objectives for all the awards measure improvement in Constellation Holdings' net income over the same three year period. In making long-term incentive awards the Committee considers the desired amount of total compensation and the appropriate mix among base salary, short-term incentive compensation, and long-term incentive compensation. The Committee sets long-term incentive target amounts to bring total compensation in line with survey data for the relevant labor market. Measures for performance-based long-term incentive awards are based upon total shareholder return. The Committee evaluated the total director compensation package and, together with their counterparts from PEPCO, will recommend the compensation package that makes the most sense for the new company. Matters under consideration include whether compensation should be paid in stock, cash or a mix, and what structure (a retainer, meeting fees, and other benefits, if any) is optimal. The Committee has determined to terminate retirement benefits for BGE directors in 1997. Any vested benefits will be replaced with annuities purchased on the termination date; all non-vested benefits will terminate. Section 162(m) of the Internal Revenue Code limits tax deductions for executive compensation to $1 million. There are several exemptions to Section 162(m), including one for qualified performance-based compensation. To be qualified, performance-based compensation must meet various requirements, including shareholder approval. The Committee has considered annually whether it should adopt a policy regarding 162(m) and concluded it was not appropriate to do so. One reason for the conclusion is that, assuming the current compensation policies and philosophy remain in place, Section 162(m) will not be applicable in the near term for any executive's compensation. However, the Committee also notes that while generally it wishes to maximize the deductibility of compensation, the Committee believes the 162(m) requirements are not fully consistent with sound executive compensation policy and incentives to improve shareholder value. Therefore, the Committee may in the future approve incentive payments that do not qualify for deduction if the recipient's compensation exceeds the $1 million limit. Jerome W. Geckle, Chairman Dan A. Colussy J. Owen Cole Michael D. Sullivan 68 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth the beneficial ownership of common stock of the Company of the five executive officers shown in the Summary Compensation Table on page 62, and all directors and executive officers as a group as of January 17, 1997. None of such persons beneficially owns shares of any other class of equity securities of the Company.
BENEFICIAL OWNERSHIP NAME (SHARES OF COMMON STOCK)(1) ---- --------------------------- Bruce M. Ambler....................................................................... 36,418(2) H. Furlong Baldwin.................................................................... 750 Beverly B. Byron...................................................................... 1,000 J. Owen Cole.......................................................................... 4,263 Dan A. Colussy........................................................................ 1,500 George C. Creel....................................................................... 27,150(3) Edward A. Crooke...................................................................... 64,393(4) James R. Curtiss...................................................................... 300 Robert E. Denton...................................................................... 24,483 Jerome W. Geckle...................................................................... 6,961 Freeman A. Hrabowski, III............................................................. 550 Nancy Lampton......................................................................... 2,220 George V. McGowan..................................................................... 103,803(5) Christian H. Poindexter............................................................... 94,772(6) George L. Russell, Jr................................................................. 1,271 Michael D. Sullivan................................................................... 1,500 All Directors and Executive Officers as a Group (27 Individuals)......................................................... 556,233
- ----------- (1) Each of the individuals listed, as well as all directors and executive officers as a group, beneficially owned less than 1% of the Company's outstanding common stock. If the individual participates in the Company's Dividend Reinvestment and Stock Purchase Plan or the Company's Employee Savings Plan, shares held by such plans on behalf of the participant are included. (2) Includes shares awarded under the Company's Long-Term Incentive Plan. (3) Includes shares awarded under the Company's Long-Term Incentive Plan. Of the total shares, 11,848 shares are held in the name of Mr. Creel's wife of which Mr. Creel disclaims beneficial ownership. (4) Includes shares awarded under the Company's Long-Term Incentive Plan. Of the total shares, 1,057 shares are beneficially owned by Mr. Crooke with his wife, and 3,000 shares are held in trust which Mr. Crooke votes. (5) 1,476 shares are beneficially owned by Mr. McGowan with his wife. He owns the other shares directly. (6) Includes shares awarded under the Company's Long-Term Incentive Plan. Of the total shares, 18,600 shares are held in the name of Mr. Poindexter's wife, and 12,000 shares are held as trustee. On September 22, 1995, BGE and Potomac Electric Power Company ("PEPCO") signed reciprocal stock option agreements in connection with the proposed Merger ("the Merger") of BGE and PEPCO with and into Constellation Energy Corporation (formerly named RH Acquisition Corp.). Pursuant to the stock option agreements, BGE granted PEPCO an irrevocable option to purchase up to 29,357,896 shares of BGE common stock under certain circumstances if the Agreement and Plan of Merger dated as of September 22, 1995 ("the Merger Agreement") becomes terminable. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Company and certain of its subsidiaries paid legal fees to the law firm of Piper & Marbury L. L. P. of which Mr. George L. Russell, Jr., a Company director, is a partner. It is expected that the Company and subsidiaries will continue to do business with this firm in 1997. 69 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as a part of this Report: 1. Financial Statements: Report of Independent Accountants dated January 17, 1997 of Coopers & Lybrand L.L.P. Consolidated Statements of Income for three years ended December 31, 1996 Consolidated Balance Sheets at December 31, 1996 and December 31, 1995 Consolidated Statements of Cash Flows for three years ended December 31, 1996 Consolidated Statements of Common Shareholders' Equity for three years ended December 31, 1996 Consolidated Statements of Capitalization at December 31, 1996 and December 31, 1995 Consolidated Statements of Income Taxes for three years ended December 31, 1996 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. 70
EXHIBIT NUMBER - ------- *2(a) -- Agreement and Plan of Merger dated as of September 22, 1995, by and among Baltimore Gas and Electric Company, Potomac Electric Power Company, and RH Acquisition Corp. (Designated as Exhibit A in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *2(b) -- BGE Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and Electric Company and Potomac Electric Power Company. (Designated as Exhibit B1 in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *2(c) -- PEPCO Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and Electric Company and Potomac Electric Power Company. (Designated as Exhibit B2 in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *2(d) -- Registration Statement on Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799. *3(a) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.) *3(b) -- By-Laws of BGE, as amended to April 18, 1995. (Designated as Exhibit No. 3(b) in Form 10-Q dated May 11, 1995, File No. 1-1910.) *4(a) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN -------------------------------------------------------------------------- EXHIBIT DATED FILE NO. NUMBER ----- -------- ------- *August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1 *January 1, 1972 1-1910 (Form 10-K Annual Report for 1971) A-2 *July 15, 1977 2-59772 2-3 (3 Indentures) *October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a) *August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i) *January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii) *July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a) *February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i) *March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii) *March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii) *April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4 *July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a) *July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b) *October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4 *March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a) *June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).) *10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q dated November 14, 1996, File No. 1-1910.) *10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
71 *10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) 10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred Compensation Plan, as amended and restated. *10(e) -- Baltimore and Gas and Electric Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for Non-Employee Directors). (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.) *10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) *10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.) *10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) *10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.) *10(j) -- Summary 1994-96 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit No. 10(l) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) *10(k) -- Employment Agreement of Christian H. Poindexter. (Designated as Exhibit C2 in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *10(l) -- Employment Agreement of Edward A. Crooke. (Designated as Exhibit C3 in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *10(m) -- Severance Agreements between BGE and 15 key employees. (Designated as Exhibit No. 10(o) to the Annual Report on Form 10-K for the year ended December 31, 1995, File No. 1-1910.) *10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore Gas and Electric Company and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 13, 1996, File No. 1-1910.) 12 -- Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. 21 -- Subsidiaries of the Registrant. 23 -- Consent of Coopers & Lybrand L.L.P., Independent Accountants. 27 -- Financial Data Schedule. *99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.) *99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland. (Designated as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31, 1987, File No. 1-1910.)
- ---------- *Incorporated by Reference. (b) Reports on Form 8-K:
DATE FILED ITEM REPORTED ---------- ------------- December 30, 1996 Item 5. Other Events
72 BALTIMORE GAS AND ELECTRIC COMPANY AND SUBSIDIARIES SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E - -------------------------------------------- ---------- --------------------------- --------------- -------- ADDITIONS --------------------------- BALANCE CHARGED AT TO BALANCE BEGINNING COSTS CHARGED TO OTHER AT END OF AND ACCOUNTS -- (DEDUCTIONS) -- OF DESCRIPTION PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD - ----------- --------- -------- ---------------- --------------- -------- (IN THOUSANDS) Reserves deducted in the Balance Sheet from the assets to which they apply: Accumulated Provision for Uncollectibles 1996.................................... $16,390 $24,955 $ -- $(23,317)(A) $18,028 1995.................................... 14,960 19,170 -- (17,740)(A) 16,390 1994.................................... 13,957 20,557 -- (19,554)(A) 14,960 Valuation Allowance -- Net unrealized (gain) loss on available for sale securities 1996.................................... (8,401) -- (4,071)(B) -- (12,472) 1995.................................... 5,609 -- (14,010)(B) -- (8,401) 1994.................................... -- -- 5,609(B) -- 5,609 Provision for possible disallowance of replacement energy costs 1996.................................... 35,000 83,000 -- -- 118,000 1995.................................... 35,000 -- -- -- 35,000 1994.................................... 35,000 -- -- -- 35,000 Loan loss reserve 1996.................................... -- -- -- -- -- 1995.................................... -- -- -- -- -- 1994.................................... 5,123 -- -- (5,123)(C) -- Energy projects under development reserves 1996.................................... 302 5,201 -- (302)(D) 5,201 1995.................................... 1,806 -- -- (1,504)(D) 302 1994.................................... 1,778 28 -- -- 1,806
- ---------- (A) Represents principally net amounts charged off as uncollectible. (B) Represents net unrealized (gains)/losses (credited)/charged to common shareholders' equity. (C) Represents reversal of loan loss reserve due to reclassification of this amount as part of the purchase price of certain real estate partnership interests. (D) Represents removal of a reserve associated with an energy project of a subsidiary which was abandoned. 73 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Baltimore Gas and Electric Company, the Registrant, has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized. BALTIMORE GAS AND ELECTRIC COMPANY (REGISTRANT) Date: March 21, 1997 By /s/ C. H. POINDEXTER ---------------------------------- C. H. POINDEXTER CHAIRMAN OF THE BOARD Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of Baltimore Gas and Electric Company, the Registrant, and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ---- Principal executive officer and director: By /s/ C. H. POINDEXTER Chairman of the Board and March 21, 1997 --------------------------------- Director C. H. POINDEXTER Principal financial and accounting officer: By /s/ D. A. BRUNE Vice President and Secretary March 21, 1997 --------------------------------- D. A. BRUNE Directors: /s/ H. F. BALDWIN Director March 21, 1997 --------------------------------- H. F. BALDWIN /s/ B. B. BYRON Director March 21, 1997 --------------------------------- B. B. BYRON /s/ J. O. COLE Director March 21, 1997 --------------------------------- J. O. COLE /s/ D. A. COLUSSY Director March 21, 1997 --------------------------------- D. A. COLUSSY /s/ E. A. CROOKE Director March 21, 1997 --------------------------------- E. A. CROOKE /s/ J. R. CURTISS Director March 21, 1997 --------------------------------- J. R. CURTISS /s/ J. W. GECKLE Director March 21, 1997 --------------------------------- J. W. GECKLE /s/ F. A. HRABOWSKI III Director March 21, 1997 --------------------------------- F. A. HRABOWSKI III /s/ N. LAMPTON Director March 21, 1997 --------------------------------- N. LAMPTON /s/ G. V. MCGOWAN Director March 21, 1997 --------------------------------- G. V. MCGOWAN /s/ G. L. RUSSELL, JR. Director March 21, 1997 --------------------------------- G. L. RUSSELL, JR. /s/ M. D. SULLIVAN Director March 21, 1997 --------------------------------- M. D. SULLIVAN
74 EXHIBIT INDEX
EXHIBIT NUMBER - ------- *2(a) -- Agreement and Plan of Merger dated as of September 22, 1995, by and among Baltimore Gas and Electric Company, Potomac Electric Power Company, and RH Acquisition Corp. (Designated as Exhibit A in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *2(b) -- BGE Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and Electric Company and Potomac Electric Power Company. (Designated as Exhibit B1 in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *2(c) -- PEPCO Stock Option Agreement dated as of September 22, 1995, by and between Baltimore Gas and Electric Company and Potomac Electric Power Company. (Designated as Exhibit B2 in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *2(d) -- Registration Statement on Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799. *3(a) -- Charter of BGE, restated as of August 16, 1996. (Designated as Exhibit No. 3 in Form 10-Q dated November 14, 1996, File No. 1-1910.) *3(b) -- By-Laws of BGE, as amended to April 18, 1995. (Designated as Exhibit No. 3(b) in Form 10-Q dated May 11, 1995, File No. 1-1910.) *4(a) -- Supplemental Indenture between BGE and Bankers Trust Company, as Trustee, dated as of June 20, 1995, supplementing, amending and restating Deed of Trust dated February 1, 1919. (Designated as Exhibit No. 4 in Form 10-Q dated August 11, 1995, File No. 1-1910.); and the following Supplemental Indentures between BGE and Bankers Trust Company, Trustee:
DESIGNATED IN --------------------------------------------------------------------------- EXHIBIT DATED FILE NO. NUMBER ----- -------- ------- *August 1, 1967 1-1910 (Form 10-K Annual Report for 1967) D-1 *January 1, 1972 1-1910 (Form 10-K Annual Report for 1971) A-2 *July 15, 1977 2-59772 2-3 (3 Indentures) *October 15, 1989 1-1910 (Form 10-Q dated November 14, 1989) 4(a) *August 15, 1991 33-45259 (Form S-3 Registration) 4(a)(i) *January 15, 1992 33-45259 (Form S-3 Registration) 4(a)(ii) *July 1, 1992 1-1910 (Form 8-K Report for January 29, 1993) 4(a) *February 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(i) *March 1, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(ii) *March 15, 1993 1-1910 (Form 10-K Annual Report for 1992) 4(a)(iii) *April 15, 1993 1-1910 (Form 10-Q dated May 13, 1993) 4 *July 1, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(a) *July 15, 1993 1-1910 (Form 10-Q dated August 13, 1993) 4(b) *October 15, 1993 1-1910 (Form 10-Q dated November 12, 1993) 4 *March 15, 1994 1-1910 (Form 10-K Annual Report for 1993) 4(a) *June 15, 1996 1-1910 (Form 10-Q dated August 13, 1996) 4
*4(b) -- Indenture dated July 1, 1985, between BGE and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated in Registration File No. 2-98443 as Exhibit 4(a)); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated in Form 8-K, dated November 13, 1987, File No. 1-1910 as Exhibit 4(a)) and as of January 26, 1993 (Designated in Form 8-K, dated January 29, 1993, File No. 1-1910 as Exhibit 4(b).) *10(a) -- Baltimore Gas and Electric Company Executive Benefits Plan, as amended and restated. (Designated as Exhibit No. 10(a) in Form 10-Q dated November 14, 1996, File No. 1-1910.) *10(b) -- Executive Incentive Plan of the Baltimore Gas and Electric Company. (Designated as Exhibit No. 10(b) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.)
75 *10(c) -- Baltimore Gas and Electric Company 1995 Long-Term Incentive Plan. (Designated as Exhibit No. 10(c) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) 10(d) -- Baltimore Gas and Electric Company Nonqualified Deferred Compensation Plan, as amended and restated. *10(e) -- Baltimore and Gas and Electric Company Nonqualified Deferred Compensation Plan for Non-Employee Directors (formerly Baltimore Gas and Electric Company Deferred Compensation Plan for Non-Employee Directors). (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.) *10(f) -- Baltimore Gas and Electric Company Retirement Plan for Non-Employee Directors, as amended and restated. (Designated as Exhibit No. 10(f) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) *10(g) -- Summary of Baltimore Gas and Electric Company Long Term Performance Program. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1993, File No. 1-1910.) *10(h) -- Grantor Trust Agreement Dated as of July 31, 1994 between Baltimore Gas and Electric Company and Citibank, N.A. (Designated as Exhibit No. 10(h) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) *10(i) -- Summary of Constellation Holdings, Inc. Annual Incentive Plan. (Designated as Exhibit No. 10(g) to the Annual Report on Form 10-K for the year ended December 31, 1992, File No. 1-1910.) *10(j) -- Summary 1994-96 Long Term Incentive Plan of Constellation Holdings, Inc. (Designated as Exhibit No. 10(l) to the Annual Report on Form 10-K for the year ended December 31, 1994, File No. 1-1910.) *10(k) -- Employment Agreement of Christian H. Poindexter. (Designated as Exhibit C2 in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *10(l) -- Employment Agreement of Edward A. Crooke. (Designated as Exhibit C3 in the Joint Proxy Statement of Baltimore Gas and Electric Company and Potomac Electric Power Company, which was filed as part of Form S-4 of Constellation Energy Corporation, as amended, which became effective February 9, 1996, Registration No. 33-64799.) *10(m) -- Severance Agreements between BGE and 15 key employees. (Designated as Exhibit No. 10(o) to the Annual Report on Form 10-K for the year ended December 31, 1995, File No. 1-1910.) *10(n) -- Grantor Trust Agreement dated as of June 1, 1996 between Baltimore Gas and Electric Company and T. Rowe Price Trust Company. (Designated as Exhibit No. 10(b) in Form 10-Q dated August 13, 1996, File No. 1-1910.) 12 -- Computation of Ratio of Earnings to Fixed Charges and Computation of Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements. 21 -- Subsidiaries of the Registrant. 23 -- Consent of Coopers & Lybrand L.L.P., Independent Accountants. 27 -- Financial Data Schedule. *99(a) -- Indemnification of Directors and Officers of the Company. (Designated as Exhibit No. 28(a) to the Annual Report on Form 10-K for the year ended December 31, 1988, File No. 1-1910.) *99(b) -- Corporations and Associations Article, Section 2-418 of the Annotated Code of Maryland. (Designated as Exhibit 28(b) to the Annual Report on Form 10-K for the year ended December 31, 1987, File No. 1-1910.)
*Incorporated by Reference. 76 EX-10 2 EXHIBIT 10(D) EXHIBIT 10(D) BALTIMORE GAS AND ELECTRIC COMPANY NONQUALIFIED DEFERRED COMPENSATION PLAN (PLAN) 1. OBJECTIVE. The objective of this Plan is to enable certain management employees of BGE and its subsidiaries to defer compensation. 2. DEFINITIONS. All words beginning with an initial capital letter and not otherwise defined herein shall have the meaning set forth in the Employee Savings Plan. All singular terms defined in this Plan will include the plural and VICE VERSA. As used herein, the following terms will have the meaning specified below: "Basic Compensation" means such compensation as set forth in the Employee Savings Plan, without regard to the Internal Revenue Code Section 401(a)(17) annual compensation limitation. "BGE" means Baltimore Gas and Electric Company, a Maryland corporation, or its successor. "Committee" means the Committee on Management of the Board of Directors of BGE. "Deferred Compensation" means any compensation payable by BGE or its subsidiaries to a participant that is deferred under the provisions of this Plan. "Employee Savings Plan" means the Baltimore Gas and Electric Company Employee Savings Plan as may be amended from time to time, or any successor plan. "Executive Incentive Plan" means the Executive Incentive Plan of Baltimore Gas and Electric Company as may be amended from time to time, or any successor plan, and/or any other incentive plan designated in writing by the Plan Administrator. "Incentive Award" means an award granted under the Executive Incentive Plan or the Managers' Incentive Plan. "Managers' Incentive Plan" means the Managers' Incentive Plan of Baltimore Gas and Electric Company as may be amended from time to time, or any successor plan, and/or any other incentive plan designated in writing by the Plan Administrator. "Matching Contributions" means the matching contributions described in Section 8. "Plan Accounts" means amounts of a participant's Deferred Compensation, Matching Contributions, and earnings under the Plan. "Plan Administrator" means, as set forth in Section 3, the Vice President -- Management Services of BGE, (or the Vice-President succeeding to that function). "Rabbi Trust" means the trust established by BGE pursuant to Grantor Trust Agreement dated as of June 1, 1996 between BGE and T. Rowe Price Trust Company. "Termination From Employment with BGE" means a participant's separation from service with BGE or a subsidiary of BGE; however, a participant's transfer of employment to or from a subsidiary of BGE shall not constitute a Termination From Employment with BGE. 3. PLAN ADMINISTRATION. The Vice President -- Management Services of BGE, (or the Vice-President succeeding to that function) is the Plan Administrator and has the sole authority (except as specified otherwise herein) to interpret the Plan, and, in general, to make all other determinations advisable for the administration of the Plan to achieve its stated objective. Appeals of written decisions by the Plan Administrator may be made to the Committee. Decisions by the Committee shall be final and not subject to further appeal. The Plan Administrator shall have the power to delegate all or any part of his/her duties to one or more designees, and to withdraw such authority, by written designation. 4. ELIGIBILITY AND PARTICIPATION. Each officer or key employee of BGE or its subsidiaries, or employees of BGE or its subsidiaries who hold manager level positions, may be designated in writing by the Plan Administrator as eligible to participate with respect to one or more of the provisions of 77 Sections 5, 6, 7 and 8, which designation will also indicate whether all or part of such participant's Plan Accounts will be held in the Rabbi Trust. Once designated, eligibility shall continue until such designation is withdrawn at the discretion and by written order of the Plan Administrator. Notwithstanding subsequent withdrawal of eligibility of an employee, such an employee with Plan Accounts will remain a participant of the Plan, except that no further deferrals of compensation under the Plan are permitted. While designated as eligible with respect to one or more of the provisions of Sections 5, 6, 7 or 8, an employee may participate in the Plan to the extent set forth in such designation. 5. BASIC COMPENSATION DEFERRAL ELECTION. Unless otherwise designated in writing by the Plan Administrator, a participant may defer Basic Compensation as set forth in this Section 5. A participant may elect to defer up to 15% of monthly Basic Compensation. A participant may also elect to defer up to 100% of Basic Compensation, if any, in excess of the dollar limitation set forth in Internal Revenue Code Section 401(a)(17) (as adjusted by the Commissioner for increases in the cost of living in accordance with Internal Revenue Code Section 401(a)(17)(B)). Any deferrals shall be in 1% multiples, subject to adjustment as necessary to provide for any required withholding taxes. Such election shall be made by notification in the form and manner established by the Plan Administrator from time to time, and shall be effective as of the beginning of the month following the month during which the election is received by the Plan Administrator. Such election may be revoked by notification in the form and manner established by the Plan Administrator from time to time, and shall be effective as of the beginning of the month following the month during which the revocation is received by the Plan Administrator. 6. INCENTIVE AWARD DEFERRAL ELECTION. A participant may elect to defer Incentive Award compensation in 1% multiples, subject to adjustment as necessary to provide for any required withholding taxes. Such election shall be made annually by notification in the form and manner established by the Plan Administrator from time to time. Such annual election shall be made prior to the Incentive Award performance year, and shall be effective as of the first day of such performance year. If a participant initially becomes eligible to participate in the Plan during a performance year, the election for such performance year must be made prior to the date the participant initially becomes eligible to participate in the Plan, and shall be effective on such date. Elections under this Section are irrevocable once effective. 7. OTHER DEFERRAL ELECTION. A participant may elect to defer, in 1% multiples, other forms of compensation that are designated in writing by the Plan Administrator. Such election must be made prior to the date the compensation is earned by the participant, by notification in the form and manner established by the Plan Administrator from time to time. Such election is effective as of the date the compensation is earned. Elections under this Section are irrevocable once effective. 8. MATCHING CONTRIBUTIONS. Matching Contributions are made by BGE to the Plan in an amount equal to (i) up to the rate of Company Matching Contributions under the Employee Savings Plan multiplied by a participant's monthly Basic Compensation deferral, less (ii) the amount of Company Matching Contributions made to the Employee Savings Plan on behalf of such participant with respect to such month. 9. PLAN ACCOUNTS. Deferred Compensation and Matching Contributions shall be (i) credited to participant Plan Accounts as soon as practicable; (ii) to the extent designated by the Plan Administrator, held for the benefit of the participant in the Rabbi Trust; and (iii) credited with earnings at the T. Rowe Price Prime Reserve Fund rate. However, a participant may elect (by notification in the form and manner established by the Plan Administrator from time to time) to have all or a portion of his/her Plan Accounts credited with earnings at a rate equal to the T. Rowe Price Prime Reserve Fund rate, the T. Rowe Price New Income Fund rate, or one or more of the rates earned by investment options available under the Employee Savings Plan, except the Common Stock Fund and the Interest Income Fund. Earnings are credited to Plan Accounts commencing on the day the Deferred Compensation and Matching Contributions are credited to the Plan Accounts. Plan Accounts will be valued daily in the same manner as for Investment Funds under the Employee Savings Plan. A participant may elect to change the investment option of future Deferred Compensation and Matching Contributions, which election shall be effective when the next Deferred Compensation 78 contributions and/or Matching Contributions are credited to the participant's Plan Accounts. A participant may elect to reallocate to other investment options current Plan Accounts, which election shall be effective at the same time as, and valued in accordance with, the interfund transfer provisions under the Employee Savings Plan. Such elections shall be made by notification in the form and manner established by the Plan Administrator from time to time. 10. DISTRIBUTIONS OF PLAN ACCOUNTS. Distributions of Plan Accounts shall be made in cash only, and to the extent designated by the Plan Administrator, from the Rabbi Trust. Prior to the end of the calendar year of a participant's Termination From Employment with BGE, such participant must elect the timing of distributions of his/her Plan Accounts. The participant may elect (by notification in the form and manner established by the Plan Administrator from time to time) to begin distributions (i) in the calendar year following the calendar year of the participant's Termination From Employment with BGE, (ii) in the year following the year in which a participant attains age 70-1/2, if later, or (iii) any calendar year between (i) and (ii). A participant may elect (by notification in the form and manner established by the Plan Administrator from time to time) to receive distributions in a single payment or in annual installments during a period not to exceed fifteen years. The single payment or the first installment payment, whichever is applicable, shall be made within the first sixty (60) days of the calendar year elected for distribution. Subsequent installments, if any, shall be made within the first sixty (60) days of each succeeding calendar year until the participant's Plan Accounts have been paid. In the event no election is made prior to the end of the year of a participant's Termination From Employment with BGE, a participant shall receive a distribution in a single payment within the first sixty (60) days of the following year. Earnings are credited to Plan Accounts through the date of distribution, and amounts held for installment payments shall continue to be credited with earnings, as specified in Section 9. If a participant dies, the entire unpaid balance of his/her Plan Accounts shall be paid to the beneficiary(ies) designated by the participant by notification in the form and manner established by the Plan Administrator from time to time or, if no designation was made, to the estate of the participant. Payment shall be made within sixty (60) days after notice of death is received by the Plan Administrator, unless prior to the end of the calendar year of the participant's Termination From Employment with BGE, the participant elected (in the form and manner established by the Plan Administrator from time to time) a delayed and/or installment distribution option for such beneficiary(ies); provided, however that (i) such a distribution option election shall be effective only if the value of the participant's Plan Accounts is more than $50,000 on the date of the participant's death; and (ii) the final distribution must be made to such beneficiary(ies) no later than 15 years after the participant's death. After the end of the calendar year of a participant's Termination From Employment with BGE, a distribution option election for a particular beneficiary is irrevocable; provided, however, that the participant may make a distribution option election for a new beneficiary who is initially designated after the participant's Termination From Employment with BGE, and such election is irrevocable with respect to the new beneficiary. In the event a participant's deferred Incentive Award is credited to the Plan after the participant's death, such Incentive Award shall be either paid to his/her beneficiary(ies), or if a delayed and/or installment distribution option was elected for such beneficiary(ies), paid as part of the aggregate Plan Accounts in accordance with such election. Upon the death of a participant's beneficiary for whom a delayed and/or installment distribution option was elected, the entire unpaid balance of the participant's Plan Accounts shall be paid to the beneficiary(ies) designated by the participant's beneficiary by notification in the form and manner established by the Plan Administrator from time to time or, if no designation was made, to the estate of the participant's beneficiary. Payment shall be made within sixty (60) days after notice of death is received by the Plan Administrator. Notwithstanding anything herein contained to the contrary, the Committee shall have the right in its sole discretion to vary the manner and timing of distributions, and may make such distributions in a single payment or over a shorter or longer period of time than that elected by a participant. 11. BENEFICIARIES. A participant shall have the right to designate a beneficiary(ies) who is to receive a distribution(s) pursuant to Section 10 in the event of the death of the participant. A participant's 79 beneficiary(ies) for whom a delayed and/or installment distribution option was elected shall have the right to designate a beneficiary(ies) who is to receive a distribution pursuant to Section 10 in the event of the death of the participant's beneficiary(ies). Any designation, change or recision of the designation of beneficiary shall be made by notification in the form and manner established by the Plan Administrator from time to time. The last designation of beneficiary received by the Plan Administrator shall be controlling over any testamentary or purported disposition by the participant (or, if applicable, the participant's beneficiary(ies)), provided that no designation, recision or change thereof shall be effective unless received by the Plan Administrator prior to the death of the participant (or, if applicable, the participant's beneficiary(ies)). If the designated beneficiary is the estate, or the executor or administrator of the estate, of the participant (or, if applicable, the participant's beneficiary(ies)), a distribution pursuant to Section 10 may be made to the person(s) or entity (including a trust) entitled thereto under the will of the participant (or, if applicable, the participant's beneficiary(ies)), or, in the case of intestacy, under the laws relating to intestacy. A participant's beneficiary(ies) for whom a delayed and/or installment distribution option was elected shall have the right, after the death of the participant, to make investment elections or changes in investment elections with respect to a participant's Plan Accounts to the same extent available to the participant pursuant to Section 9. A beneficiary(ies) of the participant's beneficiary(ies) shall have no right to make any investment election or change in investment election pursuant to Section 9 with respect to a participant's Plan Accounts. 12. VALUATION OF INTEREST. The Plan Administrator shall cause the value of a participant's Plan Accounts, at least once per year as of December 31, to be determined separately and be reported to BGE and the participant (or, if applicable, the participant's beneficiary(ies)). Valuation of a participant's Plan Accounts shall be determined in accordance with the procedures contained in the Employee Savings Plan. 13. WITHDRAWALS. No withdrawals of Plan Accounts may be made, except a participant may at any time request a hardship withdrawal from his/her Plan Accounts if he/she has incurred an unforeseeable emergency. An unforeseeable emergency is defined as severe financial hardship to the participant resulting from a sudden and unexpected illness or accident of the participant (or of his/her dependents), loss of the participant's property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the participant. The need to send a child to college or the desire to purchase a home are not considered to be unforeseeable emergencies. The circumstance that will constitute an unforeseeable emergency will depend upon the facts of each case. A hardship withdrawal will be permitted by the Plan Administrator only as necessary to satisfy an immediate and heavy financial need. A hardship withdrawal may be permitted only to the extent reasonably necessary to satisfy the financial need. Payment may not be made to the extent that such hardship is or may be relieved (i) through reimbursement or compensation by insurance or otherwise, (ii) by liquidation of the participant's assets, to the extent the liquidation of such assets would not itself cause severe financial hardship, or (iii) by cessation of deferrals under the Plan. The request for hardship withdrawal shall be made by notification in the form and manner established by the Plan Administrator from time to time. Such hardship withdrawal will be permitted only with approval of the Plan Administrator. The participant will receive a lump sum payment after the Plan Administrator has had reasonable time to consider and then approve the request. 14. MISCELLANEOUS. A participant's Plan Accounts shall not be subject to alienation or assignment by any participant or beneficiary nor shall any of them be subject to attachment or garnishment or other legal process except (i) to the extent specially mandated and directed by applicable State or Federal statute; and (ii) as requested by the participant or beneficiary to satisfy income tax withholding or liability. This Plan may be amended from time to time or suspended or terminated at any time. All amendments to this Plan which would increase or decrease the compensation of any senior management officer or key employee of BGE, either directly or indirectly, must be approved by the Board of 80 Directors. All other permissible amendments may be made at the written direction of the Committee. No amendment to or termination of this Plan shall prejudice the rights of any participant or beneficiary entitled to receive payment hereunder at the time of such action. Participation in this Plan shall not constitute a contract of employment between BGE and any person and shall not be deemed to be consideration for, or a condition of, continued employment of any person. The Plan, notwithstanding the creation of the Rabbi Trust, is intended to be unfunded for purposes of Title I of the Employee Retirement Income Security Act of 1974. BGE shall make contributions to the Rabbi Trust in accordance with the terms of the Rabbi Trust. Any funds which may be invested and any assets which may be held to provide benefits under this Plan shall continue for all purposes to be a part of the general funds and assets of BGE and no person other than BGE shall by virtue of the provisions of this Plan have any interest in such funds and assets. To the extent that any person acquires a right to receive payments from BGE under this Plan, such rights shall be no greater than the right of any unsecured general creditor of BGE. This Plan shall be governed in all respects by Maryland law. 81 EX-12 3 EXHIBIT 12 EXHIBIT 12 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED AND PREFERENCE DIVIDEND REQUIREMENTS
12 Months Ended ------------------------------------------------------- December December December December December 1996 1995 1994 1993 1992 ------------------------------------------------------- (In Thousands of Dollars) Net Income $310,824 $338,007 $323,617 $309,866 $264,347 Taxes on Income 169,202 172,388 156,702 140,833 105,994 -------- -------- -------- -------- -------- Adjusted Net Income $480,026 $510,395 $480,319 $450,699 $370,341 -------- -------- -------- -------- -------- Fixed Charges: Interest and Amortization of Debt Discount and Expense and Premium on all Indebtedness $203,923 $206,666 $204,206 $199,415 $200,848 Capitalized Interest 15,664 15,050 12,427 16,167 13,800 Interest Factor in Rentals 1,548 2,099 2,010 2,144 2,033 -------- -------- -------- -------- -------- Total Fixed Charges $221,135 $223,815 $218,643 $217,726 $216,681 -------- -------- -------- -------- -------- Preferred and Preference Dividend Requirements: (1) Preferred and Preference Dividends $ 38,536 $ 40,578 $ 39,922 $ 41,839 $ 42,247 Income Tax Required 20,849 20,434 19,074 18,763 16,729 -------- -------- -------- -------- -------- Total Preferred and Preference Dividend Requirements $ 59,385 $ 61,012 $ 58,996 $ 60,602 $ 58,976 -------- -------- -------- -------- -------- Total Fixed Charges and Preferred and Preference Dividend Requirements $280,520 $284,827 $277,639 $278,328 $275,657 -------- -------- -------- -------- -------- Earnings (2) $685,497 $719,160 $686,535 $652,258 $573,222 -------- -------- -------- -------- -------- Ratio of Earnings to Fixed Charges 3.10 3.21 3.14 3.00 2.65 Ratio of Earnings to Combined Fixed Charges and Preferred and Preference Dividend Requirements 2.44 2.52 2.47 2.34 2.08
(1) Preferred and preference dividend requirements consist of an amount equal to the pre-tax earnings that would be required to meet dividend requirements on preferred stock and preference stock. (2) Earnings are deemed to consist of net income that includes earnings of BGE's consolidated subsidiaries, equity in the net income of BGE's unconsolidated subsidiary, income taxes (including deferred income taxes and investment tax credit adjustments), and fixed charges other than capitalized interest. EX-21 4 EXHIBIT 21 EXHIBIT 21 SUBSIDIARIES OF THE REGISTRANT*
JURISDICTION OF INCORPORATION ------------- Constellation Holdings, Inc. ..................................................................... Maryland Constellation Investments, Inc. .................................................................. Maryland Constellation Energy Source, Inc. (formerly named BNG, Inc.)...................................... Delaware Safe Harbor Water Power Corporation............................................................... Pennsylvania BGE Home Products & Services, Inc................................................................. Maryland BGE Energy Projects & Services, Inc............................................................... Maryland
*The names of certain indirectly owned subsidiaries have been omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary pursuant to Rule 1-02(w) of Regulation S-X. 83 EX-23 5 EXHIBIT 23 EXHIBIT 23 CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS We consent to the incorporation by reference in the Prospectuses of Baltimore Gas and Electric Company prepared in accordance with the requirements of Forms S-8 (File Nos. 33-56084 and 33-59545) and Forms S-3 (File Nos. 33-49801, 33-45260, 33-33559, 33-57658, and 333-19263) and the Prospectus of Constellation Energy Corporation prepared in accordance with the requirements of Form S-4 (File No. 33-64799) of our report dated January 17, 1997 accompanying the consolidated financial statements and the consolidated financial statement schedule of Baltimore Gas and Electric Company as of December 31, 1996 and 1995 and for each of the three years in the period ended December 31, 1996, included in this Annual Report on Form 10-K of Baltimore Gas and Electric Company. /s/ Coopers & Lybrand L.L.P. ______________________________ COOPERS & LYBRAND L.L.P. Baltimore, Maryland March 28, 1997 EX-27 6 FINANCIAL DATA SCHEDULE
UT This schedule contains summary financial information extracted from BGE's December 31, 1996 Interim Consolidated Income Statement, Balance Sheet and Statement of Cash Flows and is qualified in its entirety by reference to such statements. 1,000 12-MOS DEC-31-1996 JAN-01-1996 DEC-31-1996 PER-BOOK 5,582,350 1,473,165 902,198 593,257 0 8,550,970 1,429,942 0 1,419,065 2,857,113 134,500 210,000 2,758,769 0 0 333,185 197,772 83,000 0 0 1,976,631 8,550,970 3,153,247 166,333 2,483,782 2,650,115 503,132 6,130 509,262 198,438 310,824 38,536 272,288 233,109 217,622 701,947 1.85 1.85
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