-----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, DFJqpIWtsFcbPzp4hQvopgJIEQGNXoEH1xaVw8Q6uM8JwGa8atYb5SI1hM6GO+53 48krGkxA4eLP59Bu7OUx4A== 0000079732-99-000004.txt : 19990201 0000079732-99-000004.hdr.sgml : 19990201 ACCESSION NUMBER: 0000079732-99-000004 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19990129 ITEM INFORMATION: FILED AS OF DATE: 19990129 FILER: COMPANY DATA: COMPANY CONFORMED NAME: POTOMAC ELECTRIC POWER CO CENTRAL INDEX KEY: 0000079732 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 530127880 STATE OF INCORPORATION: VA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: SEC FILE NUMBER: 001-01072 FILM NUMBER: 99516050 BUSINESS ADDRESS: STREET 1: 1900 PENNSYLVANIA AVE NW STREET 2: C/O M T HOWARD RM 841 CITY: WASHINGTON STATE: DC ZIP: 20068 BUSINESS PHONE: 2028722000 8-K 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 Form 8-K CURRENT REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of Report (Date of earliest event reported) January 29, 1999 POTOMAC ELECTRIC POWER COMPANY (Exact name of registrant as specified in its charter) District of Columbia and Virginia 1-1072 53-0127880 (State or other jurisdiction of (Commission (I.R.S. Employer incorporation) File Number) Identification No.) 1900 Pennsylvania Avenue, N. W., Washington, D. C. 20068 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (202) 872-2000 (Former Name or Former Address, if Changed Since Last Report) Pepco Form 8-K Item 7. Financial Statements, Pro-Forma Financial Information and Exhibits. Exhibits Exhibit No. Description of Exhibit Reference 12 Computation of ratios...............Filed herewith. 23 Consent of Independent Accountants.........................Filed herewith. 27 Financial Data Schedule.............Filed herewith. 99 The 1998 consolidated financial statements of the Company and Subsidiary, together with the report thereon of PricewaterhouseCoopers dated January 25, 1999; and Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition as well as selected financial data......................Filed herewith. Pepco Form 8-K Signatures Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. Potomac Electric Power Company (Registrant) By ___________________________ Dennis R. Wraase Senior Vice President and Chief Financial Offier January 29, 1999 DATE EX-99 2 Item 7 Exhibit 99 Financial Information - --------------------- Potomac Electric Power Company and Subsidiaries Contents - -------- Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition...................................... 2 Report of Independent Accountants.......................... 38 Consolidated Statements of Earnings........................ 39 Consolidated Balance Sheets................................ 40 Consolidated Statements of Cash Flows...................... 42 Consolidated Statements of Comprehensive Income............ 43 Notes to Consolidated Financial Statements................. 44 Selected Consolidated Financial Data....................... 90 1 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition - ---------------------------------------------------- GENERAL - ------- As an investor-owned electric utility, the Company is capital intensive, with a gross investment in property and plant of approximately $3 for each $1 of annual total revenue. The costs associated with property and plant investment amounted to 46% of the Company's total revenue in 1998. Fuel and purchased energy, capacity purchase payments and other operating expenses were 54% of total revenue. Potomac Capital Investment Corporation (PCI), a wholly owned subsidiary of the Company, conducts nonutility investment programs and businesses with the objective of supplementing current utility earnings and building long-term shareholder value. Potomac Electric Power Company Trust I (Trust), the Company's wholly owned business trust and subsidiary, was established in April 1998 for the purposes of issuing Trust Securities representing undivided beneficial interests in the assets of the Trust, and investing the gross proceeds from the sale of the Trust Securities in Junior Subordinated Debentures of the Company. The Company has two segments, consisting of its utility and nonutility operations. The utility segment derives its revenue from the generation, transmission, distribution and sale of electric energy, while the nonutility segment, which primarily consists of the operations of PCI, derives its revenue from investment programs, energy-related businesses, and telecommunication services. See the discussion included in Notes (1) and (15) of the Notes to Consolidated Financial Statements, Organization and Summary of Significant Accounting Policies - New Accounting Standards and Segment Information, respectively, for additional information. The information set forth below discusses the results of operations, capital resources and liquidity during the period 1996 through 1998 for the Company and its subsidiaries. 2 The Company's earnings for common stock during 1998 totaled $208.3 million, as compared to $165.3 million in 1997. As set forth below, utility basic earnings per common share from operations increased from $1.53 in 1997 to $1.63 in 1998, excluding the December 1997 write-off of 28 cents per share related to the cancellation of the proposed merger with Baltimore Gas and Electric Company (BG&E). Consolidated basic earnings per common share increased from $1.39 in 1997 to $1.76 in 1998. - ----------------------------------------------------------------- 1998 1997 1996 - ----------------------------------------------------------------- Utility Operations $1.63 $1.53 $1.72 Merger Costs - (.28) - Nonutility Subsidiary .13 .14 .14 ----- ----- ----- Consolidated $1.76 $1.39 $1.86 ===== ===== ===== - ----------------------------------------------------------------- The average number of common shares outstanding at December 31, 1998, was relatively unchanged from December 31, 1997. FORWARD LOOKING STATEMENTS - -------------------------- This Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition contains forward looking statements, as defined by the Private Securities Litigation Act of 1995, with regard to matters that could have an impact on the future operations, financial results or financial condition of the Company. These statements are based on the current expectations, estimates or projections of management and are not guarantees of future performance. Actual results may differ materially from those anticipated by the forward looking statements, depending on the occurrence or nonoccurrence of future events or conditions that are difficult to predict and generally are beyond the control of the Company. All such forward looking statements relating to the following matters are qualified by the cautionary statements below and contained elsewhere herein. Growth in Demand, Sales and Capacity to Fulfill Demand ------------------------------------------------------ The actual growth in demand for and sales of electricity within the Company's service territory may vary from the statements made concerning the anticipated growth in demand and sales, depending upon a number of factors, including weather conditions, the competitive environment, general economic conditions and the demographics of the Company's service territory. Future construction expenditures 3 (including the need to construct additional generation capacity) may vary from the projections, depending on the accuracy of management's expectations regarding growth in demand for and sales of electricity, regulatory developments including potential changes in environmental regulations, and the evolution of the competitive marketplace for electricity. Competition ----------- Increased competition will have an impact on future results of operations, which may be adverse, and will depend, among other factors, upon governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC) and the Maryland and District of Columbia public service commissions, future economic conditions and the influence exerted by emerging market forces over the structure of the electric industry. Year 2000 Readiness Disclosure ------------------------------ The Company has implemented a 4-pronged approach to address compliance with the Year 2000 processing requirements of its computer systems. The phases being addressed are: Corporate Applications Readiness, which includes all large core business systems; Embedded Systems, which include all operating and control systems; End-User Computing Systems, which are all systems which are not considered core business systems but contain date calculations; and Business Partners' Systems and Vendor Supply-Chain Verification, which is intended to monitor suppliers' compliance with Year 2000 processing. A database has been developed to identify and track the progress of work on each phase. The preliminary target date for completion of these phases is mid-1999. The cost or consequences of a material incomplete or untimely resolution of the Year 2000 problem could adversely affect future operations, financial results or financial condition of the Company. 4 UTILITY - ------- RESULTS OF OPERATIONS - --------------------- Total Revenue - ------------- The changes in total revenue are shown in the following table. - ----------------------------------------------------------------- Increase (Decrease) from Prior Year 1998 1997 1996 - ----------------------------------------------------------------- (Millions of Dollars) Change in kilowatt-hour sales $ 51.8 $ (8.6) $(11.5) Change in base rate revenue 24.0 (7.2) 27.0 Change in fuel adjustment clause billings to cover cost of fuel and interchange and capacity purchase payments (2.9) (9.2) (4.5) Change in other revenue 2.4 1.0 1.4 ------- ------- ------ Change in operating revenue 75.3 (24.0) 12.4 ------- ------- ------ Change in interchange deliveries 125.1 (122.8) 121.8 ------- ------- ------ Change in total revenue $ 200.4 $(146.8) $134.2 ======= ======= ====== - ----------------------------------------------------------------- The increase in 1998 base rate revenue compared to 1997 primarily reflects the effects of increases in Maryland base rates of $24 million and $19 million (effective November 1997 and December 1998, respectively) and an increase in the District of Columbia Demand Side Management (DSM) surcharge tariff of $9 million (effective September 1998); partially offset by reductions of $3.2 million and $17 million in the Maryland DSM surcharge tariff (effective September 1998 and June 1997, respectively) and a $2.5 million reduction (effective January 1998) in rates for wholesale service to the Southern Maryland Electric Cooperative (SMECO). The decrease in 1997 base rate revenue compared to 1996 primarily reflects the June 1997 decrease in the Maryland DSM surcharge (which includes a $7.3 million reduction in the conservation incentive provision of the tariff). The increase in base rate revenue in 1996 as compared to 1995 reflects the effects of a District of Columbia base rate increase of $27.9 5 million (effective July 1995) and an increase of $17.7 million (effective August 1996) associated with the Company's Maryland DSM surcharge. Fluctuations in interchange delivery transactions throughout 1998 resulted in three revisions to the Company's Maryland fuel rate. The Company increased its Maryland fuel rate by 10.5% effective March 1, 1998. Subsequently, on August 14, 1998, the Company filed for a 5.3% decrease in the Maryland fuel rate, which became effective beginning the billing month of September 1998. Also, on October 19, 1998, the Company filed for an additional 6.3% decrease in the Maryland fuel rate, which became effective beginning the billing month of November 1998. In September 1997, the Company had reduced its Maryland fuel rate by 9.5%; included in this reduction was an adjustment for a deferred fuel amortization credit to refund over a twelve month period approximately $20.7 million of previously overrecovered fuel costs incurred through June 30, 1997. The increase in 1998 in revenue from interchange deliveries reflects changes in prices and levels of energy delivered to the Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM) and changes in prices and levels of bilateral energy sales under the Company's wholesale power sales tariff. Interchange transactions are subject to cost-based ratemaking regulations based on formulas prescribed by the FERC. The decrease in 1997 in revenue from interchange deliveries reflects the termination of purchase-for-resale agreements under the Company's wholesale power sales tariff, whereby the Company purchased energy from one party (recording a corresponding expense within Purchased energy) for the purpose of selling that energy to a third party (and recording corresponding revenue within Interchange deliveries). In early 1997, pursuant to FERC's Order No. 888, the Company implemented an open access transmission tariff (OATT) for wheeling transactions and terminated purchase-for-resale agreements. In April 1997, PJM implemented an OATT on behalf of its transmission owners, replacing the Company's OATT. The increase in 1996 in revenue from interchange deliveries reflects the growth in the number of companies involved in power sales tariff interchange transactions, and changes in levels and prices of energy delivered to PJM. Interchange deliveries also include revenue from sales of short-term generating capacity. Revenues from capacity transactions totaled approximately $4.4 million, $2.9 million and $.6 million in 1998, 1997 and 1996, respectively. Presently, the Company has agreements for installed capacity sales through May 31, 1999 totaling 232 megawatts. The benefits derived from interchange deliveries, the allocated amounts of capacity sales 6 in the District of Columbia (approximately 40%) and revenue under the OATT are passed through to the Company's customers through fuel adjustment clauses. Kilowatt-hour Sales - ------------------- - ----------------------------------------------------------------- 1998 1997 vs. vs. 1998 1997 1996 1997 1996 - ----------------------------------------------------------------- (Millions of Kilowatt-hours) By Customer Type Residential 6,745 6,552 6,869 2.9% (4.6)% Commercial 12,049 11,811 11,712 2.0 .8 U.S. Government 3,968 3,934 3,902 .9 .8 D.C. Government 858 850 847 .9 .4 Wholesale (primarily SMECO) 2,678 2,561 2,570 4.6 (.4) ------ ------ ------ Total energy sales 26,298 25,708 25,900 2.3 (.7) ====== ====== ====== Interchange Energy deliveries 2,246 822 7,063 100.0+ (88.4) ====== ====== ====== By Geographic Area Maryland, including wholesale 16,017 15,601 15,763 2.7 (1.0) District of Columbia 10,281 10,107 10,137 1.7 (.3) ------ ------ ------ Total energy sales 26,298 25,708 25,900 2.3 (.7) ====== ====== ====== - ----------------------------------------------------------------- Kilowatt-hour sales increased in 1998 resulting from an increase in cooling degree hours of 15% from 1997. Cooling degree hours however were 7.5% less than the 20-year average. In addition, a .8% increase in customers produced a favorable impact on kilowatt-hour sales. Kilowatt-hour sales decreased .7% in 1997 resulting from decreases in cooling degree hours of 5% and 21% from the 1996 and 20-year average, respectively, partially offset by a .8% increase in customers. Assuming future weather conditions approximate historical averages, the Company expects its compound annual growth in retail kilowatt-hour sales to be approximately 2% over the next decade. On June 26, 1998, the Company established an all-time summer peak demand of 5,807 megawatts. This compares with the 1997 summer peak demand of 5,689 megawatts, and the prior all-time summer peak demand of 5,769 megawatts, which occurred in July 7 1991. The Company's present generation capability, excluding short-term capacity transactions, is 6,806 megawatts. At the time of the 1998 summer peak demand, the Company's energy use management (EUM) programs had the capability of reducing system demand by an additional 242 megawatts. Based on average weather conditions, the Company estimates that its retail peak demand will grow at a compound annual rate of approximately 2%, reflecting anticipated service area growth trends. The 1997-1998 winter season peak demand of 4,076 megawatts was 18.6% below the all-time winter peak demand of 5,010 megawatts which was established in January 1994. Operating Expenses - ------------------ Fuel, Purchased Energy and Capacity Purchase Payments - ----------------------------------------------------- - ----------------------------------------------------------------- 1998 1997 1996 - ----------------------------------------------------------------- (Millions of Dollars) Fuel expense $380.2 $319.6 $327.8 ------ ------ ------ Purchased energy PJM 146.3 86.6 114.6 Other 123.5 114.0 221.4 ------ ------ ------ Total purchased energy 269.8 200.6 336.0 ------ ------ ------ Fuel and purchased energy $650.0 $520.2 $663.8 ====== ====== ====== Capacity purchase payments $155.7 $150.9 $125.8 ====== ====== ====== - ----------------------------------------------------------------- Net System Generation and Purchased Energy were as follows. - ----------------------------------------------------------------- 1998 1997 1996 - ----------------------------------------------------------------- (Millions of Kilowatt-hours) Net system generation 21,715 18,322 18,041 ====== ====== ====== Purchased energy 8,204 9,371 16,157 ====== ====== ====== - ----------------------------------------------------------------- The 1998 increase in fuel expense compared to 1997 reflects an increase of 18.5% in net generation, partially offset by a decrease in the system average unit fuel cost. Although net 8 generation increased 1.6% in 1997 compared to 1996, fuel expense decreased due to the timing of fuel billed to customers through the Company's fuel rates. The Company's unit costs of fuel burned and the percentages of system fuel requirements obtained from coal, oil and natural gas are shown in the following table. - ----------------------------------------------------------------- Percent of Unit Cost Fuel Burned of Fuel Burned ------------------- -------------------------------- System Coal Oil Gas Coal Oil Gas Average - ----------------------------------------------------------------- (Per Million Btu) 1998 84.5 12.7 2.8 $1.55 $2.71 $2.63 $1.72 1997 89.1 6.4 4.5 1.65 3.80 2.87 1.84 1996 89.7 6.9 3.4 1.62 3.55 2.92 1.80 - ----------------------------------------------------------------- The 1998 system average unit fuel cost decreased by 6.5% due to decreases in the costs of coal, residual oil and gas. The increase of approximately 2% in the 1997 system average unit fuel cost compared with the 1996 system average resulted primarily from an increased unit cost of coal. The increase in the percent of oil burned in 1998 reflects a decline in the price of oil. The decrease in the percent of oil burned in 1997 reflects the increase in the price of oil and the increased usage of lower- cost gas. The Company's major cycling and certain peaking units can burn either natural gas or oil, which provides protection against possible supply disruptions, and adds flexibility in selecting the most cost-effective fuel mix. The use of coal, oil and natural gas also depends upon the availability of generating units, energy and demand requirements of interconnected utilities, regulatory requirements, weather conditions, and fuel supply constraints, if any. The Company seeks to maintain a minimum unit cost of energy through the economic dispatch of its generating facilities, active participation in the bulk power market and purchases of generating capacity. The Company's generating and transmission facilities are interconnected with those of other transmission owners in the PJM power pool and other utilities, providing economic energy and reliability benefits by facilitating the Company's participation in the federally-regulated wholesale energy market. This market has enabled the Company to purchase energy at costs lower than those required to self-generate, and to sell energy at favorable prices to other market participants. 9 Energy transactions within the PJM power pool are priced at rates which are approved by the FERC and are based on each power pool participant's marginal cost. In April 1997, PJM implemented a competitive "bid-based" energy marketplace, where companies offered energy at prices not exceeding their cost of producing the energy, and transactions occurred at the market's marginal clearing price. In November 1997, the FERC conditionally approved a PJM restructuring plan which, among other things, established an independent system operator (ISO) having responsibility for system operations and regional transmission planning. The Commission authorized the independent body that operates the ISO to also operate the PJM power exchange. On April 1, 1998, the unconstrained market clearing pricing system for purchased energy was replaced by a "locational marginal pricing" system designed to economically control transmission system congestion. Because of the Company's generation availability and peak load characteristics, the Company generally is able to sell into the PJM market during high price peak load periods and buy from the market during low price periods. (Also see the Restructuring of the Bulk Power Market discussion below). In addition to interchange within PJM, the Company is actively participating in the bilateral energy sales marketplace. The Company's FERC-approved wholesale power sales tariff allows both sales from Company-owned generation and sales of energy purchased by the Company from other market participants. Numerous utilities and marketers have executed service agreements allowing them to arrange purchases under this tariff and the Company has executed service agreements allowing it to purchase energy under other market participants' power sales tariffs. The Company continues to purchase energy from FirstEnergy Corp. (FirstEnergy, formerly Ohio Edison) under the Company's 1987 long-term capacity purchase agreement with FirstEnergy and Allegheny Energy, Inc. (AEI). Pursuant to this agreement, the Company is purchasing 450 megawatts of capacity and associated energy through the year 2005. The Company purchases energy from the Panda-Brandywine, L.P. (Panda) facility pursuant to a 25-year power purchase agreement for 230 megawatts of capacity supplied by a gas-fueled combined-cycle cogenerator; capacity payments under this agreement commenced in January 1997. The Company is also purchasing 50 megawatts of capacity and related energy from the Northeast Maryland Waste Disposal Authority under a short term avoided cost-based purchase agreement. The capacity expense under these agreements, including an allocation of a portion of FirstEnergy's fixed operating and maintenance costs, was $149.8 million for 1998, $145.2 million for 1997 and $120 million for 1996. Commitments under these agreements are estimated at $203 million for 1999, $204 million for 2000, $209 million for 2001, and $210 million for 2002 and 2003. 10 The Company also has a purchase agreement with SMECO, through 2015, for 84 megawatts of capacity supplied by a combustion turbine installed and owned by SMECO at the Company's Chalk Point Generating Station. The Company is responsible for all costs associated with operating and maintaining the facility. The capacity payment to SMECO is approximately $5.5 million per year. The Company's customers are charged separate rates designed to recover the actual cost of fuel used to generate electricity, including the net cost of purchased energy less interchange deliveries. Differences between actual costs of fuel and energy, and fuel revenues collected are deferred on the Consolidated Balance Sheets. The Company earns no return on costs eligible for recovery within these fuel rates. The District of Columbia fuel rate includes a provision for the current recovery of purchased capacity costs as well as a provision for the credit for capacity sales. In Maryland, purchased capacity costs are recovered in base rates. As electricity becomes more actively traded as a commodity, the bulk power market is developing methods for traders to hedge against price volatility. Both the New York Mercantile Exchange (NYMEX) and the Chicago Board of Trade (CBOT) have introduced futures contracts for electricity for various delivery points across the country. NYMEX's recently introduced "Into Cinergy" contract has outpaced the others in liquidity. NYMEX is planning to refile its PJM futures contract with the Commodity Futures Trading Commission to reflect a Western Hub delivery point and the CBOT has announced its intention to introduce a PJM contract. In addition, some market participants are using customized instruments to hedge prices for both capacity and energy. Such instruments include forward contracts to fix prices, options to set ceilings or floors on prices and swaps to exchange variable prices for a fixed price. The mid-Atlantic energy market is expected to feature a secondary market in transmission congestion hedging. The Company's current activity in these markets is insignificant, and all activity is passed on to customers through the Company's fuel adjustment clause mechanism. However, in the future, the Company expects to increase its participation in the hedging markets as part of its strategy to control costs and avoid unreasonable risks. In some instances, as part of its overall bulk power marketing activity, the Company may offer to sell hedging instruments. 11 Other Operation and Maintenance Expenses - ---------------------------------------- Other operation and maintenance expenses totaled $329.2 million for 1998. These expenses increased by $13.6 million (4.3%) in 1998, principally due to non-recurring charges of $8.2 million for operating costs associated with the Company's Targeted Severance Plan (the Plan). The Plan offers severance pay and subsidized health and dental benefits, at amounts dependent upon years of service, to employees who lose employment due to corporate restructuring and/or job consolidations. Under the Plan, no changes were made to eligible pensions or benefits under the retirement program. During 1998, 177 employees participated in the Plan. Increases in other operation and maintenance expenses in 1998 were also due to $5.7 million in expenditures associated with the Company's efforts to accommodate the Year 2000. The Company's approach to testing and remediating Year 2000-related issues, and developing business continuation and contingency plans is discussed in detail below. Other operation and maintenance expenses increased by $.8 million (.2%) in 1997, principally due to increases in electric plant maintenance expense, partially offset by reduced labor and benefits costs. The Company's budget and cost control disciplines have resulted in a 17% decline in the number of Company employees since 1995. Year 2000 Readiness Disclosure ------------------------------ The Company has implemented a 4-pronged approach to accommodate the Year 2000. All phases are coordinated through a Corporate Year 2000 Task Force comprised of representatives from each Business Unit. The phases being addressed are as follows: 1. Corporate Applications (Information Technology) Readiness: Corporate Applications are large core systems such as Customer Information, Human Resources and General Ledger, for which the Company's Computer Services Group (CSG) has responsibility. Year 2000 modifications to these systems are being programmed and tested by CSG. 2. Embedded Systems (Non-Information Technology Processes): These systems include items such as meters, power plant operating and control systems, telecommunications systems and facilities-based equipment (e.g. elevators). These products are being evaluated and modified as required by the appropriate internal end-user, in coordination with the systems' vendors. 12 3. End-User Computing Systems (Non-Core [Departmental] Business Systems): Corporate areas other than CSG have developed systems, databases, spreadsheets, etc. that contain date calculations. These products are being evaluated and modified as required by the appropriate end-user. 4. Business Partners' Systems and Vendor Supply-Chain Verification: The Company is seeking to obtain Year 2000 assurances from numerous vendors who provide products and services to the Company. This effort is being jointly undertaken by the Company's Materials Group and appropriate end-users. The Task Force meets regularly to monitor the status of the efforts of the Company's assigned staff, contractors, and vendors in testing and remediating Year 2000 related issues. Task Force Subcommittees are addressing additional Year 2000 related issues including, but not limited to, customer communications, testing procedures and business continuation and other contingency planning. As of December 31, 1998, approximately 99% of the changes required to the 110 corporate IT systems have been made and regression tested. The Company's mainframe computer system has been partitioned so that a portion is isolated from the production environment and used for Year 2000 full-cycle, or "time machine," testing. This testing encompasses not only the date change from 12/31/1999 to 1/1/2000, but also many of the other potentially troublesome dates, including 2/29/2000. A total of 80% of corporate IT systems have been tested in the time machine. Among the major applications successfully tested are the Customer Information, Accounts Payable, Materials Management, and Construction Management systems. End-user computing testing in the time machine will begin in January 1999. A parallel LAN (local area network) Year 2000 testing facility has been established. All standard LAN office automation and operating systems applications supported by Computer Services have been tested successfully. The first series of LAN business applications supported by Computer Services is currently in testing. The LAN test lab will be available for business units to test their applications beginning in January 1999. Assessments of critical operational systems containing embedded systems were completed in October 1998 by teams of vendors, contractors and Company personnel. Year 2000 upgrades to the distributed control systems of Potomac River Units 1, 2, 3, 4 and 5 and Chalk Point Units 2 and 4 have been completed and tested. Remediation efforts are in process at other plants and areas of the electric system. A total of 95% of mission-critical substation, system protection and distribution controls are 13 expected to be Year 2000 ready by January, 1999. The Energy Management System (EMS) is critical to the operation of the electric system. Factory acceptance testing for the Year 2000 mitigation software has successfully been completed and the new software will be installed, tested, and operational by June 1, 1999. In total, 65% of EMS/Substation Control and Data Acquisition facilities will be Year 2000 ready by January 1999. In addition to including Year 2000 remediation and testing as part of regularly scheduled plant outages, special Year 2000 outages have been scheduled in the winter of 1998-99 and spring of 1999. Test scheduling is more complex for embedded systems because of the difficulty inherent in scheduling power plant outages to accommodate the testing. In addition, some vendors are requesting that their customers refrain from testing certain components because of the potential difficulties in recovering from such tests. These vendors have either advised that their product is Year 2000 ready or have invited Company representatives to participate in testing at their facilities. As of December 31, 1998 all affected plant units have outages planned for Year 2000 testing. This differs from the original plan to test one typical unit of each type. To accommodate this change of scope, the completion date for all Year 2000 testing of critical and high priority components has been revised from March 31, 1999 to June 30, 1999. This target date may be impacted by the integration testing plans and scheduled generation/electric systems outage decisions inherent in embedded systems processing. As of December 31, 1998, based upon the Company's evaluation to date, it appears that all identified Year 2000 impacted processing components can be upgraded, modified or otherwise made Year 2000 ready within acceptable time frames. End-user computing systems comprise a relatively small percentage of the required modifications both in terms of number and criticality. All activities remain on schedule to be completed by mid-1999. The Company is participating in an Electric Power Research Institute sponsored consortium of approximately 100 organizations and investor-owned utilities to coordinate vendor contacts and product evaluation. Since many embedded systems are similar across utilities, this cooperative effort should help to reduce total time expended in this area and help ensure that the Company's efforts are consistent with the efforts and practices of other investor-owned utilities. The United States Department of Energy requested that the North American Electric Reliability Council (NERC) prepare a comprehensive report outlining the efforts of electric power supply and delivery systems to prepare for Year 2000. NERC collected data from utilities on a voluntary basis and issued reports in September 1998 and January 1999. In the last update 14 provided to NERC, the Company reported 100% completion for both the inventory and assessment phases of Year 2000, and 60% completion in the remediation phase. Major challenges remain in several areas: maintaining sufficient human resources to complete Year 2000 tasks; evaluating integrated testing requirements for many embedded systems, taking into account planned outages and operational needs; and completing contingency planning for the variety of scenarios which might occur. There are two potential areas of resource constraints. First, as the Company continues to reorganize to prepare for industry deregulation, there is a risk of losing technically and functionally knowledgeable people to remediate and test systems. However, operating areas have been instructed to give increased attention to Year 2000 staffing needs when making reorganization decisions. Second, the availability of vendor resources to complete embedded system assessments and produce in volume any required component upgrades will be a concern. Integration testing also presents a challenge because of scheduling constraints and admonitions from some vendors regarding the risks of testing. A careful evaluation of testing options and vendor testing documentation must be made on a component-by-component basis in order to determine the most appropriate method for obtaining Year 2000 readiness. Business continuation and contingency planning efforts are in progress. Business Units responsible for critical components and systems are preparing plans in case of potential failures of individual components or systems. These plans are referenced in the Year 2000 tracking database and will be incorporated into the Company's Year 2000 Business Continuity Plan. In order to ensure adequate staffing for contingencies that may arise, Company employees have been informed that vacation, floating holidays, and other discretionary leave may not be scheduled between December 26, 1999 and January 8, 2000. Recognizing that all contingency plans should support business continuity, the Company has formed a Business Continuity Plan Team to integrate contingency plans. The Company's business continuity planning will go beyond contingency planning to document actions to be taken, resources required, and procedures to be followed to ensure the continued availability of essential services, programs, and operations in the event of unexpected interruptions. 15 The following steps will be used for business continuity planning: 1. Identification of Year 2000 Operating Risks - Identify sources of risk, both internal and external, which may impact the Company's ability to sustain reliable operations into the Year 2000 and beyond. 2. Review of Existing Operating Plans - Review existing procedures to determine if a Year 2000-specific plan should be incorporated. 3. Develop Risk Management Strategies - Perform an analysis of, and make recommendations for, alternative methods of continuing critical business functions. 4. Develop Year 2000 Emergency Plan and Enhance Existing Plans - A separate Year 2000 plan will be developed that will interface with the Company's Corporate Emergency Response Plan (ERP). Modification and enhancements to existing plans will include the following: (a) Procedures to be followed before, during, and after a disaster; (b) Inventories of information needs in a disaster, such as emergency personnel lists, supplier lists, etc.; (c) Vital records risk level; (d) Analysis of means to mitigate risk; and (e) Integration of Year 2000 into the ERP. 5. Validation Process - Tests will be conducted by the Business Continuity Planning Team to include tabletop exercises and drills on likely Year 2000 scenarios. The Company's planning process includes a review of emergency coordination interfaces with the community. For example, a key facet of business continuity is the Company's interface with various emergency management agencies. The Company is participating with the Metropolitan Washington Council of Governments, which is looking at public safety issues on a regional basis using existing regional public safety and emergency management organizations. The Company presented a planning status report to the Council of Governments in November 1998 and is also actively participating with emergency management agencies in Year 2000 planning and drills. In December 1998, the Company participated with the Montgomery County Office of Emergency Preparedness in a countywide drill, as well as in a PJM Interconnection drill. In January 1999, the Company participated in a Maryland Emergency Management Agency drill. The Company will participate in the next PJM drill in March 1999. To assist in review and testing of business continuity planning, the Company has contracted with Binominal International. Binominal International, known for its contingency planning and disaster recovery expertise, is 16 assisting in the review and testing of business continuity planning, which will incorporate Year 2000 components. The first draft of the Company's Business Continuity Plan was completed in December 1998. The Company is working through the PJM Interconnection to address risks related to the regional electric transmission system. Such interconnected systems are critical to the reliability of each interconnected electric service provider, as the failure of one such interconnected provider to achieve Year 2000 readiness could disrupt others from providing electric service. Should the regional electric transmission grid become unstable, power outages could occur. The Company's existing emergency system restoration plan is being reviewed for use in the event of such Year 2000 system disruptions. NERC has responsibility for overseeing the efforts of the industry in the United States and is coordinating Year 2000 efforts and contingency planning within and between the ten electric reliability councils throughout the United States. Coordination in the Company's region is through PJM. The Company provides reports of its Year 2000 activities to NERC on a monthly basis. Results show that the Company is on schedule to meet the NERC target dates for Year 2000 readiness. The Company will participate in NERC's planned drills in April and September 1999. The availability of telecommunications services is a major concern to the Company. Telecommunications are integral to maintaining electric system operations internally, within PJM, and throughout the Northern American grid. Contingency planning for various loss of telecommunications scenarios is underway. The Company agrees with NERC's September 1998 report to the United States Department of Energy regarding the various Year 2000 scenarios that could occur. NERC has divided these into "more probable scenario types," such as loss or unavailability of a portion of generation, loss of a portion of system monitoring and control functions, loss of voice communications, loss of a portion of load, or uncharacteristic load; and "credible worst- case scenarios," such as loss of a portion of transmission facilities, underfrequency load shedding, and loss of intra- or interregional communications. The Company's Business Continuity Planning Team will be evaluating scenarios such as these and developing appropriate response plans. The Company has established a range of communications to keep customers and suppliers informed of Year 2000 efforts. During September 1998, Year 2000 briefing seminars were held for many large customers. Individual meetings with several large customers have also been held. A bill insert has been used to advise customers of Year 2000 activities; future bill inserts will be used as needed. A brochure for customers inquiring about 17 the Company's Year 2000 efforts is available and being distributed. The brochure will be posted on the Company's web page on the Internet, and the web page will be updated periodically with the latest Year 2000 status information. An updated telephone script has been developed for customer service representatives answering Year 2000 related telephone inquiries from customers. The Company has contacted over 6,000 suppliers and vendors to seek assurance that they will continue to provide goods and services after December 1999. Follow-up contacts continue. Identified essential suppliers will be defined as critical dependencies in the draft Business Continuity Plan. The cost or consequences of a material incomplete or untimely resolution of the Year 2000 problem could adversely affect future operations, financial results or financial condition of the Company. The cost of expected modifications will be approximately $14 million, and will be charged to expense as incurred. This estimate may change as additional evaluations are completed and remediation and testing progresses. Through December 31, 1998, $7 million has been charged to expense; the remaining costs will be expensed in 1999. Approximately $5.7 million, or 40% of the total cost, was expensed in the twelve months ended December 31, 1998. Depreciation and Amortization Expense, Income Taxes and Other Taxes - ------------------------------------------------------- Depreciation and amortization expense increased by $7.8 million (3.4%) in 1998, and by $9 million (4%) in 1997, due to additional investment in property and plant. Changes in income taxes in 1998 and 1997 reflect changes in the levels of taxable operating income. Other taxes increased by $2.7 million (1.3%) in 1998, reflecting increases in the levels of plant investment and operating revenue, upon which taxes are based. Other taxes increased by $1.3 million (.6%) in 1997, reflecting increases and partially offsetting decreases in the levels of plant investment and operating revenue, respectively. Other Income, including Allowance for Funds Used During Construction and Capital Cost Recovery Factor - ------------------------------------------------------- Other income reflects net earnings from PCI of $15.1 million in 1998, $17.1 million in 1997 and $16.9 million in 1996. See the Nonutility Subsidiary discussion below and the discussion included in Note (14) of the Notes to Consolidated Financial Statements, Selected Nonutility Subsidiary Financial Information. Other income also reflects decreases in accruals for the equity 18 component of the Allowance for Funds Used During Construction (AFUDC) resulting from declining amounts of Construction Work In Progress expenditures not in rate base; and decreases in the equity component of the Capital Cost Recovery Factor (CCRF) accrued on declining amounts of pollution control expenditures related to Clean Air Act (CAA) compliance. AFUDC equity totaled $.9 million in 1998, $1 million in 1997 and $1.4 million in 1996; CCRF equity totaled $.4 million in 1998, $5.7 million in 1997 and $5.2 million in 1996. Other income for 1997 reflects a reduction of $52.5 million resulting from the write-off of costs related to cancellation of the proposed merger with BG&E; credits of $19.9 million for income taxes associated with this write-off are reflected in Other, net. CCRF accruals on unamortized District of Columbia DSM costs not in rate base, totaling $3.7 million in 1998, $5.4 million in 1997 and $4.1 million in 1996, are also reflected in Other, net. Utility Interest Charges - ------------------------ Utility interest charges were relatively stable during the three-year period 1996 through 1998, notwithstanding changes in the levels of borrowing. Short-term borrowing costs have remained relatively low. The average cost of outstanding long- term utility debt declined from 7.51% at the beginning of 1996 to 7.37% at the end of 1998. Distributions on preferred securities of the Trust totaled $5.7 million in 1998. Utility interest charges are offset by both the debt component of AFUDC which totaled $3.9 million in 1998, $3.8 million in 1997 and $3.9 million in 1996; and by the debt component of Clean Air Act CCRF which totaled $.3 million in 1998, $4 million in 1997 and $3.6 million in 1996. CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- The Company's total investment in property and plant, at original cost, was $6.7 billion at year-end 1998. Investment in property and plant construction, net of AFUDC and CCRF, was $603.3 million for the period 1996 through 1998. Internally generated cash from utility operations, after dividends, totaled $646.7 million for the period 1996 through 1998. Sales of first mortgage bonds, medium-term notes and trust originated preferred securities (TOPrS) during the period 1996 through 1998 provided a total of $406.8 million. During the years 1996 through 1998, the Company retired $354.1 million in outstanding long-term securities, including refinancings, scheduled debt maturities, preferred stock redemptions and sinking fund retirements. Interim financing was provided principally through the issuance of short-term commercial promissory notes. During the three-year period 1999 through 2001, capital resources of $314 million ($45.2 million in 1999) 19 will be required to meet scheduled debt maturities and sinking fund requirements, and additional amounts will be required for working capital and other needs. Approximately $759 million is expected to be available from depreciation and amortization charges and income tax deferrals over the three-year period of which approximately $265 million is the 1999 portion. Dividends on common stock were $196.6 million in 1998, $196.7 million in 1997 and $196.6 million in 1996. The Company's current annual dividend on common stock is $1.66 per share. The dividend rate is determined by the Company's Board of Directors and takes into consideration, among other factors, current and possible future developments which may affect the Company's income and cash flow levels. The Company has no current plans to change the dividend; however, there can be no assurance that the $1.66 dividend rate will be in effect in the future. Dividends on preferred stock were $11.4 million in 1998, $16.5 million in 1997 and $16.6 million in 1996. The embedded cost of preferred stock was 5.74% at December 31, 1998, 6.44% at December 31, 1997 and 6.41% at December 31, 1996. In June 1998, the Company redeemed 60,000 shares of Serial Preferred Stock, $3.37 series of 1987, at $50 per share for sinking fund purposes. The Company also redeemed in accordance with their terms, all of the 779,696 shares remaining after the sinking fund redemption of Serial Preferred Stock, $3.37 series of 1987, at $51.13 per share; all of the 500,000 shares of Serial Preferred Stock, $3.82 series of 1969, at $51 per share; and all of the 1,000,000 shares of Serial Preferred Stock, $3.89 series of 1991, at $53.89 per share. The redemption totaled $123.7 million and includes $6.6 million in premiums. In May 1998, the Company's wholly owned Trust issued $125 million of 7-3/8% TOPrS. The proceeds from the sale of the TOPrS and from the common securities of the Trust to the Company were used by the Trust to purchase from the Company $128.9 million of 7- 3/8% Junior Subordinated Deferrable Interest Debentures, due June 1, 2038. The sole assets of the Trust are the Subordinated Debentures. The Trust will use interest payments received from the Company on the Subordinated Debentures to make quarterly cash distributions on the TOPrS. Proceeds from the sale of the Subordinated Debentures to the Trust were used by the Company to redeem the three series of serial preferred stock in June 1998. The Company's obligation under the declaration, including its obligation to pay costs, expenses, debt and liabilities of the Trust, provides a full and unconditional guarantee on a subordinated basis of amounts payable on the TOPrS. See the discussion included in Note (9) of the Notes to Consolidated Financial Statements, Redeemable Serial Preferred Stock and Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust, for additional information. 20 Total annualized interest cost for all utility outstanding long-term debt and preferred securities of the Trust at December 31, 1998, was $139 million, compared with $132.6 million and $133 million at December 31, 1997 and 1996, respectively. Year-end 1998 outstanding utility short-term indebtedness totaled $191.7 million compared with $131.4 million at the end of 1997 and 1996. The Company's capitalization ratios (excluding nonutility subsidiary debt), at December 31, 1998, are presented below. - ----------------------------------------------------------------- Excluding Including Amounts Due Amounts Due In One Year In One Year - ----------------------------------------------------------------- Long-term debt 46.4% 43.8% Redeemable serial preferred stock 1.2 1.2 Serial preferred stock 2.5 2.3 Company obligated mandatorily redeemable preferred securities of subsidiary trust which holds solely parent junior subordinated debentures 3.1 2.9 Common equity 46.8 44.2 Short-term debt and amounts due in one year - 5.6 ----- ----- Total capitalization 100.0% 100.0% ===== ===== - ----------------------------------------------------------------- The Company maintains 100% line of credit back-up in the amount of $200 million, for its outstanding commercial promissory notes, which was unused during 1998, 1997 and 1996. Conservation - ------------ The Company's DSM and EUM programs have increased the efficiency of energy usage while successfully deferring the need for the acquisition of additional generating capacity. To reduce the near-term upward pressure on customer rates and bills, the Company is continuing to reduce its conservation offerings and limit conservation spending. This strategy recognizes the transformation of the market to generally higher levels of energy efficiency for residential and non-residential equipment. Effective March 25, 1998, the Maryland Public Service Commission approved a proposal supported by the Company to discontinue operation of all but one DSM program in Maryland. The Company received permission to substantially reduce rebates paid to program participants for the single remaining program. A 21 proposal by the Company to eliminate DSM programs operated within the District of Columbia was filed with the District of Columbia Public Service Commission in March 1998, and is pending. The effects of retail competition and updated research information on the programs' net benefits support the discontinuance of these programs. The Company recovers the costs of Maryland DSM programs through a base rate surcharge that includes a provision for the recovery of program cost amortization and permits the Company to earn a return on its DSM investment while receiving compensation for lost revenue. In addition, when energy savings have exceeded annual goals, the Company has earned a bonus. The Company was awarded a bonus of $1.3 million in 1998, based on 1997 performance, which followed bonuses of $1.6 million in 1997, based on 1996 performance, and $8.9 million in 1996, based on 1995 performance. Maryland DSM program goals have been successively reduced to reflect declining DSM expenditures. On September 16, 1998, the Company received permission from the Maryland Commission to decrease the DSM surcharge tariff effective with bills rendered on and after September 21, 1998, which will reduce annual revenue by approximately $3 million. The reduction in the surcharge rate reflects the decline in the costs and scale of Maryland DSM programs. Beginning with the September 1998 surcharge update, the program cost amortization period of five years will be successively reduced to reflect the following: 1998 program costs will be amortized over four years; 1999 program costs will be amortized over three years; 2000 program costs will be amortized over two years; and 2001 and subsequent program costs will be amortized over one year. In addition, the performance bonus provision of the surcharge relative to future energy saving goals will no longer apply. Investment in Maryland DSM programs totaled $15.4 million in 1998, $24 million in 1997 and $27.4 million in 1996. In June 1995, the District of Columbia Commission adopted a base rate surcharge mechanism that amortizes over a 10-year period actual DSM costs prudently incurred since June 30, 1993; prior to this decision, DSM costs had been considered in base rate cases. The Environmental Cost Recovery Rider (ECRR) includes both a DSM expenditure component and a component for recovering certain expenditures associated with complying with the CAA Amendments of 1990. Also within its June 1995 order, the Commission adopted a DSM spending cap for the four-year period 1995 through 1998. The Company has successfully managed its portfolio of DSM programs to ensure that the costs of these programs are within the spending limit. In June 1997, the Company filed an Application for Authority with the Commission to update the ECRR surcharge tariff to recover actual DSM expenditures incurred during the period January 1995 through December 1996. In a June 1998 filing, the Company requested that recovery of year 1997 DSM expenditures also be reflected within the ECRR. On September 3, 1998, the Commission approved the 22 Company's June 1997 request for recovery of the January 1995 through December 1996 DSM expenditures, increasing annual revenue by approximately $9 million. On October 30, 1998, the Company updated its June 1998 request for 1997 DSM expenditures to incorporate provisions of the Commission's September 3, 1998 decision, which would increase annual revenue by approximately $3 million. Investment in District of Columbia programs totaled $5.2 million in 1998, $5.1 million in 1997 and $17.9 million in 1996. In 1998, approximately 160,000 customers participated in continuing EUM programs that cycle air conditioners and water heaters during peak periods. In addition, the Company operates a commercial load curtailment program that provides incentives to customers for reducing energy usage during peak periods. Time- of-use rates have been in effect since the early 1980s and currently approximately 60% of the Company's revenue is derived from time-of-use rates. It is estimated that peak load reductions of approximately 730 megawatts have been achieved to date from DSM and EUM programs and that additional peak load reductions of approximately 50 megawatts will be achieved over the next five years. The Company also estimates that, in 1998, energy reductions of approximately 1.7 billion kilowatt-hours have been realized through operation of its DSM and EUM programs. During the next five years, the Company's projected costs for conservation programs total $19 million ($16 million in 1999). Construction and Generating Capacity - ------------------------------------ Construction expenditures, excluding AFUDC and CCRF, totaled $206 million in 1998 ($66 million related to Generation) and are projected to total $865 million ($389 million related to Generation) for the five-year period 1999 through 2003, which includes approximately $132 million of CAA expenditures. In 1999, construction expenditures are projected to total $185 million ($79 million related to Generation), which includes $22 million of estimated CAA expenditures. The Company plans to finance its construction program primarily through funds provided by operations. The Company's present generation resource mix consists of 4,815 megawatts of steam generating capacity and 1,227 megawatts from 31 combustion turbine units owned by the Company, including 166 megawatts of capacity from the Company's 9.72% undivided interest in the Conemaugh Generating Station located in western Pennsylvania. In addition, the Company has a purchase agreement with SMECO, through 2015, for 84 megawatts of generating capacity supplied by a combustion turbine installed and owned by SMECO at the Company's Chalk Point Generating Station. A network of 23 transmission and distribution facilities delivers power from these generation resources to customers and provides for system reliability. On December 31, 1998, the Company and SMECO entered into a new full-requirements agreement that supersedes the existing rolling-10-year full service power supply requirements contract. The agreement will be effective as of January 1, 1999, if accepted by FERC without change or modification. As a result of the agreement, approximately 600 megawatts of additional capacity will become available by December 31, 2001 or, at SMECO's option, December 31, 2000. See the discussion included in Note (13) of the Notes to Consolidated Financial Statements, Commitments and Contingencies, for additional information. The Company projects that existing contracts for nonutility generation and the emerging wholesale market for generation resources will provide adequate reserve margins to meet customers' needs beyond the year 2000. The Company continues to purchase 450 megawatts of generating capacity and associated energy from FirstEnergy under a 1987 long-term capacity purchase agreement with FirstEnergy and AEI. The Company also has a 25-year capacity purchase agreement with Panda for 230 megawatts of capacity from a gas-fueled combined-cycle cogenerator in Prince George's County, Maryland. Pursuant to the terms of an October 1997 amendment to this agreement, Panda is permitted to broker sales of certain amounts of the Company's system capacity from January 1998 through May 2000, and to broker or sell energy from the Panda facility. Panda will pay the Company for the right to broker capacity sales, as well as a fee based on actual energy sales. CLEAN AIR ACT - ------------- The Company has complied with Phase I of the Acid Rain portion of the CAA. Phase II of the CAA, effective January 1, 2000, requires further reductions in nitrogen oxides (NOx) emissions and sulfur dioxide (SO2) emissions (or the acquisition of additional SO2 allowances) from the Company's generating units. NOx emissions reductions are being achieved by installing new boiler burner controls and equipment at the Company's Dickerson Generating Station. Obligations for SO2 emissions reductions will be met by continued use of lower sulfur coal, supplemented by SO2 allowance purchases as necessary. Anticipated capital expenditures for complying with the second phase of the CAA total approximately $34 million. In addition to the Acid Rain portion of the CAA, the State of Maryland and District of Columbia are required, by Title I of the CAA, to achieve compliance with ambient air quality standards for ground-level ozone. On May 22, 1998 the State of Maryland issued final regulations entitled "Post RACT Requirements for Nitrogen Oxides (NOx) Sources (NOx Budget Proposal)," requiring a 65% reduction in NOx emissions at the Company's Maryland generating units by 24 May 1, 1999. The regulations allow the purchase or trade of NOx emission allowances to fulfill this obligation. The Company appealed this regulation to the Circuit Court for Charles County, Maryland on June 19, 1998, on the basis that the regulation does not provide adequate time for the installation of NOx emission reduction technology and that there is no functioning NOx allowance market. On July 17, 1998, the case was moved to the Circuit Court for Baltimore City and consolidated with a similar appeal filed by BG&E. The Company believes it is unlikely that a market in NOx allowances sufficient to ensure compliance will be functioning by May 1999; presently, eight states have enacted the rules necessary to create such a market. A preliminary plan for installing the best available removal technology on the Company's largest coal-fired units would require capital expenditures of approximately $170 million and would yield NOx reductions of nearly 85% beginning in year 2004. The Company cannot predict the outcome of this litigation and is evaluating its options in the event of an adverse decision. Also, on September 24, 1998, the EPA issued rules for reducing interstate transport of ozone. The Company's preliminary plan for NOx reductions of 85% by 2004 appears to be consistent with the EPA rules. The Company owns a 9.72% undivided interest in the Conemaugh Generating Station located in western Pennsylvania. NOx emissions reduction equipment and flue gas desulfurization equipment were installed at the station in 1994 for compliance with Phases I and II of the CAA. The Company's share of construction costs for this equipment was $36.2 million. As a result of installing the flue gas desulfurization equipment, the station has received additional SO2 emission allowances. The Company's share of these bonus allowances is being used to reduce the need for lower-sulfur fuel at its other plants. In December 1997, U.S. representatives at the climate change negotiations in Kyoto, Japan, agreed to the reduction of greenhouse gas emissions in certain portions of the developed world. The Kyoto protocol is subject to conditions which may not occur, and is also subject to ratification by the United States Senate, which has indicated that it will not ratify an agreement unless certain conditions, not currently provided for in the Kyoto protocol, are met. At present, it is not possible to predict whether the Kyoto protocol will attain the force of law in the United States or what its impact would be on the Company. Further developments in connection with the Kyoto process could adversely affect future operations, financial results or financial condition of the Company. BASE RATE PROCEEDINGS - --------------------- The Company is subject to utility rate regulation based upon the historical costs of plant investment, using recent test years to measure the cost of providing service. The rate-making process 25 does not give recognition to the current cost of replacing plant and the impact of inflation. Changes in industry structure and regulation may affect the extent to which future rates are based upon current costs of providing service. The regulatory commissions have authorized fuel rates which provide for billing customers on a timely basis for the actual cost of fuel and interchange and for emission allowance costs and, in the District of Columbia, for purchased capacity. Annual base rate increases (decreases) which became effective during the period 1996 through 1998 are shown below. - ----------------------------------------------------------------- District of Year Total Maryland Columbia Wholesale - ----------------------------------------------------------------- (Millions of Dollars) 1998 $16.5 $19.0 $ - $(2.5) 1997 24.0 24.0 - - 1996 (2.0) - - (2.0) ----- ----- ----- ----- $38.5 $43.0 $ - $(4.5) ===== ===== ===== ===== - ----------------------------------------------------------------- Maryland - -------- On November 28, 1998, pursuant to a settlement agreement, the Maryland Public Service Commission authorized a $19 million, or 2% increase in base rate revenue effective with service rendered on and after December 1, 1998. In June 1998, the Company had filed a request to increase its base rates to recover contractual escalations in existing Commission-approved purchased capacity contracts, costs related to the 1998 Targeted Severance Plan, Year 2000 compliance costs, tax normalization of pre-1981 plant removal costs, and certain other costs associated with prior ratemaking determinations. The settlement's rate increase was distributed among rate classes in a manner that will continue movement toward equalized rates of return among rate classes, and provided for a lessening of the Company's summer-winter rate differential. The settlement was comprehensive and does not include specific determinations regarding an authorized rate of return; however, a rate of return of 8.80% will be used by the Company, beginning in December 1998, for purposes of calculating AFUDC and CCRF. Previously, pursuant to a November 1997 settlement agreement, the Commission authorized a $24 million, or 2.6%, increase in base rate revenue effective with bills rendered on and after November 30, 1997. 26 District of Columbia - -------------------- In July 1995, the District of Columbia Public Service Commission authorized rates that are based on a 9.09% rate of return on average rate base, including an 11.1% return on common stock equity and a capital structure which excludes short-term debt. Wholesale - --------- The Company has a full service power supply requirements contract with SMECO, the Company's principal wholesale customer with a peak load of approximately 600 megawatts, which represents approximately 10% of the Company's total kilowatt-hour sales. See the discussion included in Note (13) of the Notes to Consolidated Financial Statements, Commitments and Contingencies, for additional information. COMPETITION - ----------- Since the early 1980s, the Company has pursued strategies which achieve financial flexibility through conservation and EUM programs, extension of the useful life of generating equipment, cost-effective purchases of capacity and energy, and preservation of scheduling flexibility to add new generating capacity in relatively small increments. The Company serves a unique and stable service territory and is a low-cost energy producer with customer prices that compare favorably with regional and national averages. In response to the electric utility industry's transition from regulation to a more competitive market, the Company during 1997 began to make fundamental changes in the shape and direction of its organizational units. Utility operations were reconfigured into three primary business units: generation, distribution and transmission. The structures of these organizational units continued to unfold in 1998 and are expected to offer the focus and flexibility necessary to maneuver in whatever competitive form the industry finally takes. Such reorganization allows the Company to make the best use of its assets while concentrating the efforts of employees on making each business unit profitable. 27 In reconfiguring utility operations into generation, distribution and transmission business units, the Company has decided not to seek to become a larger generation company. The net book value of the Company's generating assets at December 31, 1998 is $1.8 billion. The Company's generating assets are relatively small in comparison to other major utilities and it is expected that through future consolidations, there will remain only a few large generating companies in the country. The Company's immediate focus will be on increasing the performance and profitability of its existing generation in the deregulated wholesale market. The Company intends to explore whether it should establish joint partnerships with other utilities' generating business units, create strategic alliances, divest its generating assets or continue its present course. In the area of transmission, which remains under federal regulation, the Company believes it has certain strengths and skills. The Company intends to continue to evaluate the cost effectiveness of its transmission system with a view to expanding profit potential, including the possibility of adding to the Company's transmission assets. In the area of distribution, which continues to be regulated at the local level, the Company believes it has valuable assets and skills and intends to continue to enhance its profitability locally and leverage its skills elsewhere. The Company is currently engaged in regulatory proceedings in Maryland where the Public Service Commission has outlined steps and established dates for the phase-in implementation of competition. In the District of Columbia, the Public Service Commission is considering various issues regarding electric industry structure and competition. The Company reaffirms its full support for customer choice for its electric customers, and has provided key principles to be used as guidelines for its introduction. These principles include the concept that present suppliers should not be put at a competitive disadvantage by customer choice, that competition should not be regulated, and that the benefits of customer choice should not be oversold. Increased competition will have an impact on future results of operations, which may potentially be adverse. The nature of this competition will depend upon the actions of governmental and regulatory agencies, future regional economic conditions and influences exerted by emerging market forces over the structure of the electric industry. See the discussion included in Note (13) of the Notes to Consolidated Financial Statements, Commitments and Contingencies, for additional information. 28 RESTRUCTURING OF THE BULK POWER MARKET - -------------------------------------- The FERC issued its Final Rulemaking Orders No. 888 and No. 889 in April 1996 to further its goal of achieving greater competition in the wholesale energy market. Order No. 888 required utilities to file open access transmission tariffs and separately price generation, transmission and ancillary services. Order No. 889 directed utilities to establish or participate in an Open Access Same-time Information System (OASIS) where transmission owners post certain transmission availability, pricing and service information on an open-access communications medium such as the Internet. Order No. 889 also required the separation of utilities' transmission system operations and wholesale marketing functions. In November 1997, FERC issued an Order approving the establishment of PJM as an ISO to administer transmission service under a poolwide transmission tariff and provide open access transmission service on a poolwide basis. The ISO, which began operation on January 1, 1998, is now responsible for system operations and regional transmission planning. In addition, the Commission decided that the independent body that operates the ISO may also operate the PJM power exchange. The Commission approved the power pool's use of single, non-pancaked transmission rates to access the eight transmission systems which make up PJM. Each transmission owner within PJM has its own transmission rate, whereby the transmission customer will pay a single rate based on the cost of the transmission system where the generating capacity is delivered. This PJM rate design has been in effect since April 1997. The Commission also approved, effective April 1, 1998, locational marginal pricing for allocating scarce transmission capability. This method is based on price differences in energy at the various locations on the transmission system. PJM has many years of experience in providing economically efficient transmission and generation services throughout the mid-Atlantic region, and has achieved for its members, including the Company, significant cost savings through shared generating reserves and integrated operations. The PJM members have transformed the previous coordinated cost-based pool dispatch into a bid-based regional energy market operating under a standard of transmission service comparability. Benefits and/or costs derived from the PJM market are passed through to the Company's customers through fuel adjustment clauses and, accordingly, will not have a material effect on the operating results of the Company. 29 NEW ACCOUNTING STANDARDS - ------------------------ See the discussion included in Note (1) of the Notes to Consolidated Financial Statements, Organization and Summary of Significant Accounting Policies. ENVIRONMENTAL MATTERS - --------------------- The Company is subject to federal, state and local legislation and regulation with respect to environmental matters, including air and water quality and the handling of solid and hazardous waste. As a result, the Company is subject to environmental contingencies, principally related to possible obligations to remove or mitigate the effects on the environment of the disposal, effected in accordance with applicable laws at the time, of certain substances at various sites. During 1998, the Company participated in environmental assessments and cleanups under these laws at four federal Superfund sites and a private party site as a result of litigation. While the total cost of remediation at these sites may be substantial, the Company shares liability with other potentially responsible parties. Based on the information known to the Company at this time, management is of the opinion that resolution of these matters will not have a material effect on the results of operations or financial position of the Company. See the discussion included in Note (13) of the Notes to Consolidated Financial Statements, Commitments and Contingencies, for additional information. 30 NONUTILITY SUBSIDIARY - --------------------- RESULTS OF OPERATIONS - --------------------- Over the past several years, the focus of PCI and its subsidiaries has shifted from financial investments in aircraft, leases and securities to that of a provider of energy, telecommunications and related products and services in the Northern Virginia/Washington, D.C./Baltimore metropolitan area. PCI is seeking to shift this focus by installing and employing leading-edge technologies; by attempting to realize significant economies of scale from multi-product marketing and the use of common facilities and support services, wherever appropriate; and by endeavoring to deliver high-quality, convenient and reliable services at competitive prices. PCI's businesses consist of four separate components: Mass Market, Commercial Market, Utility Related Market, and Financial Investments. During 1998, PCI expanded its customer service and product offerings through strategic partnerships and with acquisitions of energy and telecommunications businesses. Mass Market ----------- In December 1997, wholly owned affiliates of PCI and RCN Corporation entered into a 50/50 joint venture to create Starpower Communications (Starpower). In 1998, Starpower became the first company to begin offering a complete single-source package of local and long-distance telephone and Internet services to customers throughout the Washington, D.C. metropolitan area. With planned initial investments of $150 million from each partner over a three year period (1998-2000), Starpower has begun building a 6,000 mile fiber optic network to ultimately serve homes and businesses in a geographic area that extends from Northern Virginia to Baltimore. High population density areas have been targeted for the initial build-out of the fiber optics system, and Starpower will begin supplying cable television to residential customers in portions of the District of Columbia and Maryland during 1999. As of December 31, 1998, PCI has invested $20 million of its total $150 million commitment to Starpower. PCI's portion of Starpower's pre-tax loss for 1998 is $10.6 million. PCI expects that the joint venture will continue to incur losses in 1999 and 2000 as it develops and expands its network and customer base. During the first quarter of 1998, RCN 31 acquired Erols Internet. The majority of Erols customers (approximately 197,000 out of a total 316,000 in February 1998) are located in Starpower's target market. These customer accounts, as well as certain associated network assets and related liabilities, have been contributed by RCN to Starpower. Starpower has agreed to pay $51.9 million ($78.6 million in assets, primarily goodwill, net of $26.7 million of unearned revenue) through a ratable reduction to RCN's committed future capital contributions. As a result of this transaction, Starpower is amortizing the acquisition premium over a three to five year period commencing February 1998. Starpower has recently signed agreements with the City of Gaithersburg and the District of Columbia to provide video programming, to local residents as well as, local phone, long- distance and high-speed Internet access. A 147-channel cable television service through an advanced fiber-optic network is being rolled out to these jurisdictions during 1999. The commercial success of Starpower will depend upon the ability of Starpower to achieve its commercial objectives subject to a number of uncertainties and risks, including: the pace of entry into new markets; the time and expense required for building out the planned network; success in marketing services; the intensity of competition; the affect of regulatory developments; and the possible development of alternative technologies. Statements concerning the activities of Starpower that constitute forward looking statements are subject to the foregoing risks and uncertainties. Commercial Market ----------------- In September 1998, a wholly owned subsidiary of PCI purchased the net assets and operations of Gaslantic Corporation (Gaslantic), a Maryland-based natural gas retail marketing and advisory services company doing business principally in the mid-Atlantic region. Gaslantic focuses on providing advisory services to commercial, industrial and institutional end-users regarding the management of the risks and costs of natural gas procurement, and making retail sales of natural gas to such customers. It recommends purchasing strategies, negotiates supply and pipeline transportation agreements and, if requested, purchases natural gas on behalf of its clients. Gaslantic is a fee-based adviser and retail marketer rather than a gas trader. Typical of gas marketing operations, Gaslantic's purchase of energy to fulfill client contract requirements is a high volume and relatively low margin business. Through December 31, 1998, revenues recorded related to this business since its acquisition on September 10, 1998 totaled $13.3 million. With the acquisition of Gaslantic, PCI added fuel supply management and retail sales of natural gas to its inventory of integrated energy products and services, which also includes energy use assessments, facilities operation 32 and management, performance-based energy efficiency contracting, and the sale of electricity in markets open to retail competition. A wholly owned PCI subsidiary became licensed as a retail power marketer during 1998 and began selling electricity to commercial and residential customers in Pennsylvania in the fourth quarter of 1998. Through December 31, 1998, the subsidiary has signed agreements to supply a total of 10 MW of electric load to various residential and business customers in Pennsylvania, with the first deliveries of electricity scheduled to begin in February 1999. As retail competition in the sale of energy in the Washington, D.C. metropolitan region is phased in by regulators over the next several years, PCI will use the experience gained in Pennsylvania and other mid-Atlantic markets to compete in these newly opening markets. On January 25, 1999, a wholly owned unregulated subsidiary of PCI signed a contract with SMECO to supply SMECO's full requirements for power (approximately 600 MW of peak load) during the four year period starting January 1, 2001. See the discussion included in Note (13) of the Notes to Consolidated Financial Statements, Commitments and Contingencies, for additional information. In late 1998, a wholly owned subsidiary of PCI acquired the net assets and operations of MET Electrical Testing, Inc. (MET Testing). MET Testing is an electrical testing and engineering company based in Columbia, Maryland, with specialized experience in testing, inspecting, repairing, upgrading and maintaining industrial and commercial-type electrical installations and equipment. MET Testing's business is primarily in the mid- Atlantic states with clients that include major corporations, healthcare facilities, property managers and government agencies. MET Testing's annual revenues for 1998 were approximately $4.6 million. PCI expects to use MET Testing as a platform to build additional commercial services such as the operation and maintenance of commercial energy equipment. The commercial success of PCI in these markets is subject to a number of risks, including, regulatory developments and the pace of deregulation; success in marketing services; the intensity of competition; and the ability to secure electric supply to fulfill sales commitments at favorable prices. Statements concerning the activities of PCI in these markets that constitute forward looking statements are subject to the foregoing risks and uncertainties. 33 Utility Related Market ---------------------- A wholly owned subsidiary of PCI continues to own and operate W. A. Chester, a utility contractor specializing in underground transmission and cable distribution systems, and, in partnership with Columbia Energy Group, a natural gas pipeline, liquefied natural gas (LNG) storage and terminal facility, both of which are providing services to the utility industry and other customers. Financial Investments --------------------- PCI manages a portfolio of financial investments, including securities, aircraft and electric power plant leases, real estate and structured finance transactions. Its remaining aircraft portfolio is being managed with the objective of identifying future opportunities for its sale or other disposition on economic terms. PCI will continue to make new financial investments that contribute to current and future earnings. Consolidated Results -------------------- PCI's consolidated net earnings in 1998 were $15.1 million ($.13 per share), compared with consolidated net earnings of $17.1 million ($.14 per share) and $16.9 million ($.14 per share), in 1997 and 1996, respectively. During 1998, PCI recorded pre-tax gains of $12.2 million ($7.9 million after-tax) from the sale of real estate and pre-tax gains of $7.8 million ($4.6 million after-tax) from the sale of aircraft and related equipment. PCI's earnings in 1998 also include capital gains totaling $1.4 million, net of tax, related primarily to tender offers accepted by PCI which reduced dividend income and the cost basis of PCI's preferred stock portfolio by $74.4 million since year end 1997. Proceeds from asset sales were used to pay down debt, which resulted in a decrease in interest expense from 1997. PCI's 1998 consolidated net earnings included after-tax losses of $8.4 million and $1.2 million, related to its telecommunications and energy services businesses, respectively. In January 1999, PCI received cash of $6.2 million and other assets with a value of $3.3 million in an early liquidation of a partnership interest and will record $7 million in after-tax earnings in 1999. In 1998, PCI generated income primarily from its leasing activities and operating businesses. Income from leasing activities, which includes rental income, gains on asset sales, interest income and fees totaled $73.3 million in 1998, compared to $75.6 million in 1997 and $91.7 million in 1996. The decrease in income from leasing activities during 1998 was primarily due to less rental income earned in 1998 as a result of asset sales 34 earlier in the year offset by the pre-tax gains on sales of aircraft equipment. The decrease in income from leasing activities in 1997 compared to 1996 was primarily due to asset sales, resulting in lower rental income. PCI's marketable securities portfolio contributed pre-tax income of $19.3 million in 1998, $28.6 million in 1997 and $33.7 million in 1996. The decreases in income from marketable securities were primarily due to decreases in dividend income as a result of reductions in the preferred stock portfolio since 1996. Income from marketable securities included net realized gains of $2.2 million in 1998, $6.9 million in 1997 and $3.6 million in 1996. Income from energy and utility industry services increased over the prior years primarily due to 1998 acquisitions and growth in contract revenue. Other income totaled $8.4 million in 1998, compared with a loss of $1.6 million in 1997 and a loss of $11.5 million in 1996. The increase in other income for 1998 was primarily the result of $12.2 million in pre-tax gains from the sales of real estate and the 1997 pre-tax writedown of $10 million related to a real estate property. The increase in other income during 1998 was partially offset by pre-tax equity losses of $11.4 million related to PCI's 50% equity investment in Starpower and the writeoff of $3.2 million pre-tax ($2.1 million after-tax) of PCI's remaining investment in oil and natural gas. Other income increased in 1997 over 1996 as a result of pre-tax writedowns of $29 million ($18.8 million after-tax) recorded in 1996 related to PCI's investments in solar energy projects, real estate and oil and natural gas, compared to a pre-tax writedown of $10 million ($6.5 million after-tax) recorded in 1997 related to a real estate property. Expenses before income taxes, which include interest, depreciation, operating and other expenses totaled $137.1 million, $139.8 million and $159.3 million for the years ended 1998, 1997 and 1996, respectively. The decreases in expenses before income taxes in 1998 compared to 1997 and 1996 were primarily due to decreased interest expense over the three-year period as a result of reduced debt outstanding, as proceeds from sales of aircraft, marketable securities and other investments were used to pay down debt. The decreases in expenses before income taxes over the last two years were also due to reductions in depreciation resulting from the sales of aircraft. PCI had income tax credits of $8.7 million in 1998, $31.8 million in 1997 and $54.6 million in 1996. As a result of joint venture operations and other activity, including the finalization in 1998 of the Internal Revenue Services' examinations through the 1995 tax year, PCI's obligation for previously accrued 35 deferred taxes was reduced resulting in a net reduction in income tax expense during the years ended December 31, 1998, December 31, 1997 and December 31, 1996 of $1.5 million, $13.3 million and $34.9 million, respectively. Year 2000 Readiness Disclosure ------------------------------ In connection with Year 2000 compliance efforts, a PCI representative is a member of the Corporate Year 2000 Task Force. PCI is following the utility's approach, as discussed previously, for monitoring its in-house systems and PCI's systems have been included in the overall Year 2000 Corporate Data Base. All PCI in-house business systems remain on schedule to become Year 2000 compliant by June 30, 1999. Costs for these remediation efforts are currently estimated at less than $50,000. In addition, PCI is addressing potential Year 2000 issues with the operations of businesses in which PCI has investment or operating interests. The Corporate Year 2000 Task Force will be assisting PCI with its examination and monitoring of Year 2000 issues involving these strategic business interests. Issues include ascertaining responsibility for and monitoring progress of any Year 2000 remediation efforts required for investment-based business and embedded systems. Plans and progress reports have been received for most such systems. Due to the significant nature of PCI's planned investment in Starpower, PCI has instituted a Starpower- specific Year 2000 Program. Starpower receives significant support services from RCN, which completed development of its formal Year 2000 Plan in November 1998. PCI is working with Starpower and RCN toward readiness of RCN-supplied support systems, and other Starpower systems and operations with Year 2000 requirements. A contingency plan is being developed in the event that remediation efforts are not successfully completed in a timely fashion. The cost or consequences of a material incomplete or untimely resolution of the Year 2000 problem could adversely affect PCI's future operations, financial results or financial condition. CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- PCI has the capital resources necessary to carry out its business plans. PCI will supply or arrange for the capital resources needed to support the business activities of its growing operating business units. PCI issues short-term and medium-term notes under its own, separately rated commercial paper and Medium-Term Note programs. PCI's $231.1 million securities portfolio, consisting primarily of fixed-rate electric utility preferred stocks provides additional liquidity and investment flexibility. During 1998, PCI reduced the cost basis of its marketable securities portfolio by $73.4 million primarily as the result of calls and acceptance of tender offers of approximately 36 $74.4 million offset by purchases of $1 million. The reduced size of the preferred stock portfolio lessens the impact of future fluctuations in interest rates. Proceeds from securities activity and sales of assets during 1998 were used to pay down debt. PCI had no short-term debt outstanding at December 31, 1998, compared to $7.7 million at December 31, 1997. During 1998, PCI issued $220.2 million in long-term debt, including non-recourse debt, and debt payments totaled $333.7 million. PCI had cash and cash equivalents of $79.6 million available at December 31, 1998 in order to satisfy debt service requirements in early 1999. At December 31, 1998, PCI had $503 million available under its Medium-Term Note Program and $400 million of unused bank credit lines. 37 Report of Independent Accountants To the Shareholders and Board of Directors of Potomac Electric Power Company In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of earnings and comprehensive income, and of cash flows present fairly, in all material respects, the financial position of Potomac Electric Power Company and its subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. /s/ PricewaterhouseCoopers LLP Washington, D.C. January 25, 1999 38 Consolidated Statements of Earnings Potomac Electric Power Company and Subsidiaries
- -------------------------------------------------------------------------------------------------- For the year ended December 31, 1998 1997 1996 - -------------------------------------------------------------------------------------------------- (Millions of Dollars, except Per Share Data) Revenue (Note 2) Operating revenue $ 1,886.1 $ 1,810.8 $ 1,834.8 Interchange deliveries 177.8 52.7 175.5 --------- --------- --------- Total Revenue 2,063.9 1,863.5 2,010.3 --------- --------- --------- Operating Expenses Fuel 380.2 319.6 327.8 Purchased energy 269.8 200.6 336.0 Capacity purchase payments (Note 13) 155.7 150.9 125.8 Other operation 237.7 220.3 223.3 Maintenance 91.5 95.3 91.5 --------- --------- --------- Total Operation and Maintenance 1,134.9 986.7 1,104.4 Depreciation and amortization 239.8 232.0 223.0 Income taxes (Note 4) 130.5 117.7 134.1 Other taxes (Note 5) 204.4 201.7 200.4 --------- --------- --------- Total Operating Expenses 1,709.6 1,538.1 1,661.9 --------- --------- --------- Operating Income 354.3 325.4 348.4 --------- --------- --------- Other Income (Loss) Nonutility subsidiary (Note 14) Income 143.5 125.1 121.6 Expenses, including interest and income taxes (128.4) (108.0) (104.7) --------- --------- --------- Net earnings from nonutility subsidiary 15.1 17.1 16.9 Allowance for other funds used during construction and capital cost recovery factor 1.3 6.7 6.6 Write-off of merger costs (Note 13) - (52.5) - Other, net 3.2 24.0 4.5 --------- --------- --------- Total Other Income (Loss) 19.6 (4.7) 28.0 --------- --------- --------- Income Before Utility Interest Charges 373.9 320.7 376.4 --------- --------- --------- Utility Interest Charges Interest on debt 146.1 146.7 146.9 Distributions on preferred securities of subsidiary company (Note 9) 5.7 - - Allowance for borrowed funds used during construction and capital cost recovery factor (4.2) (7.8) (7.5) --------- --------- --------- Net Utility Interest Charges 147.6 138.9 139.4 --------- --------- --------- Net Income 226.3 181.8 237.0 Dividends on Preferred Stock (Notes 8 and 9) 11.4 16.5 16.6 Redemption Premium on Preferred Stock 6.6 - - --------- --------- --------- Earnings for Common Stock $ 208.3 $ 165.3 $ 220.4 ========= ========= ========= Basic Earnings Per Common Share (Note 7 $1.76 $1.39 $1.86 Diluted Earnings Per Common Share (Note 7) $1.73 $1.38 $1.82 Cash Dividends Per Common Share $1.66 $1.66 $1.66
39 Consolidated Balance Sheets Potomac Electric Power Company and Subsidiaries
- ---------------------------------------------------------------------------------------- December 31, Assets 1998 1997 - ---------------------------------------------------------------------------------------- (Millions of Dollars) Property and Plant - at original cost (Notes 6 and 10) Electric plant in service $ 6,539.9 $ 6,392.8 Construction work in progress 73.2 94.3 Electric plant held for future use 4.3 4.2 Nonoperating property 40.4 22.8 --------- --------- 6,657.8 6,514.1 Accumulated depreciation (2,136.6) (2,027.8) --------- --------- Net Property and Plant 4,521.2 4,486.3 --------- --------- Current Assets Cash and cash equivalents 6.4 5.6 Customer accounts receivable, less allowance for uncollectible accounts of $2.4 and $2.1 114.9 116.6 Other accounts receivable, less allowance for uncollectible accounts of $.3 44.8 32.3 Accrued unbilled revenue 65.6 69.3 Prepaid taxes 34.7 33.7 Other prepaid expenses 3.3 7.6 Material and supplies - at average cost Fuel 53.3 59.4 Construction and maintenance 68.7 68.1 --------- --------- Total Current Assets 391.7 392.6 --------- --------- Deferred Charges Income taxes recoverable through future rates, net (Note 4) 232.5 238.1 Conservation costs, net 197.5 221.5 Unamortized debt reacquisition costs 49.9 52.7 Other 175.6 149.0 --------- --------- Total Deferred Charges 655.5 661.3 --------- --------- Nonutility Subsidiary Assets (Note 14) Cash and cash equivalents 79.6 0.4 Marketable securities (Note 11) 231.1 302.5 Investment in finance leases (Note 14) 399.2 463.6 Operating lease equipment, net of accumulated depreciation of $120.1 and $153.5 (Note 14) 122.6 163.3 Receivables, less allowance for uncollectible accounts of $5.0 and $6.0 48.4 64.2 Other investments 120.6 162.9 Other assets 23.1 10.5 Deferred income taxes 61.8 - --------- --------- Total Nonutility Subsidiary Assets 1,086.4 1,167.4 --------- --------- Total Assets $ 6,654.8 $ 6,707.6 ========= ========= 40
- ---------------------------------------------------------------------------------------- December 31, Capitalization and Liabilities 1998 1997 - ---------------------------------------------------------------------------------------- (Millions of Dollars) Capitalization Common equity (Note 7) Common stock, $1 par value - authorized 200,000,000 shares, issued 118,527,287 and 118,500,891 shares $ 118.5 $ 118.5 Premium on stock and other capital contributions 1,025.3 1,025.2 Capital stock expense (13.7) (15.0) Accumulated other comprehensive income 7.8 6.5 Retained income 739.5 727.8 --------- --------- Total Common Equity 1,877.4 1,863.0 Preference stock, cumulative, $25 par value - authorized 8,800,000 shares, no shares issued or outstanding - - Serial preferred stock (Notes 8 and 11) 100.0 125.3 Redeemable serial preferred stock (Notes 9 and 11) 50.0 141.0 Company obligated mandatorily redeemable preferred securities of subsidiary trust which holds solely parent junior subordinated debentures (Notes 9 and 11) 125.0 - Long-term debt (Notes 10 and 11) 1,859.0 1,901.5 --------- --------- Total Capitalization 4,011.4 4,030.8 --------- --------- Other Non-Current Liabilities Capital lease obligations (Note 13) 157.6 160.4 --------- --------- Current Liabilities Long-term debt and preferred stock redemption 45.2 52.1 Short-term debt (Note 12) 191.7 131.4 Accounts payable and accrued payroll 104.5 118.4 Capital lease obligations due within one year 20.8 20.8 Taxes accrued 50.7 29.2 Interest accrued 38.0 38.3 Customer deposits 26.9 24.8 Other 68.9 67.4 --------- --------- Total Current Liabilities 546.7 482.4 --------- --------- Deferred Credits Income taxes (Note 4) 1,049.2 1,029.3 Investment tax credits (Note 4) 53.7 57.3 Other 24.6 19.1 --------- --------- Total Deferred Credits 1,127.5 1,105.7 --------- --------- Nonutility Subsidiary Liabilities Long-term debt (Notes 10 and 11) 716.9 830.5 Short-term notes payable (Note 12) - 7.7 Deferred taxes and other (Note 4) 94.7 90.1 --------- --------- Total Nonutility Subsidiary Liabilities 811.6 928.3 --------- --------- Commitments and Contingencies (Note 13) Total Capitalization and Liabilities $ 6,654.8 $ 6,707.6 ========= ========= 41
Consolidated Statements of Cash Flows Potomac Electric Power Company and Subsidiaries
- ---------------------------------------------------------------------------------------------------- For the year ended December 31, 1998 1997 1996 - ---------------------------------------------------------------------------------------------------- (Millions of Dollars) Operating Activities Income from utility operations $ 211.2 $ 164.7 $ 220.1 Adjustments to reconcile income to net cash from operating activities: Depreciation and amortization 239.8 232.0 223.0 Deferred income taxes and investment tax credits 23.1 60.5 81.5 Deferred conservation costs (24.3) (34.5) (49.4) Allowance for funds used during construction and capital cost recovery factor (5.5) (14.5) (14.1) Changes in materials and supplies 5.6 10.2 (4.1) Changes in accounts receivable and accrued unbilled revenue (7.3) 19.2 10.5 Changes in accounts payable (12.6) 6.4 13.6 Changes in other current assets and liabilities 25.8 (2.5) 5.9 Changes in deferred merger costs - 29.0 (24.2) Net other operating activities (28.9) (54.7) (24.4) Nonutility subsidiary: Net earnings 15.1 17.1 16.9 Deferred income taxes (62.7) (63.8) (36.4) Changes in other assets and net other operating activities 37.9 65.7 49.0 --------- --------- --------- Net Cash From Operating Activities 417.2 434.8 467.9 --------- --------- --------- Investing Activities Total investment in property and plant (211.7) (231.7) (194.0) Allowance for funds used during construction and capital cost recovery factor 5.5 14.5 14.1 --------- --------- --------- Net investment in property and plant (206.2) (217.2) (179.9) Nonutility subsidiary: Purchase of marketable securities (1.0) (35.1) (19.7) Proceeds from sale or redemption of marketable securities 76.6 125.0 167.5 Investment in leased equipment - (7.5) (3.1) Proceeds from sale or disposition of leased equipment 105.9 28.5 3.7 Proceeds from sale of assets - 7.3 34.2 Purchase of other investments (25.0) (20.6) (23.0) Proceeds from sale or distribution of other investments 34.3 18.7 33.9 Proceeds from promissory notes, net - 64.1 12.4 --------- --------- --------- Net Cash (Used by) From Investing Activities (15.4) (36.8) 26.0 --------- --------- --------- Financing Activities Dividends on common stock (196.6) (196.7) (196.6) Dividends on preferred stock (11.4) (16.5) (16.6) Redemption of preferred stock (123.7) (1.5) - Issuance of manditorily redeemable preferred securities 125.0 - - Issuance of long-term debt - 182.3 99.5 Reacquisition and retirement of long-term debt (51.1) (151.5) (26.3) Short-term debt, net 60.3 - (127.1) Other financing activities (3.1) (1.3) (5.4) Nonutility subsidiary: Issuance of long-term debt 220.2 40.0 183.0 Repayment of long-term debt (333.7) (205.8) (237.1) Short-term debt, net (7.7) (44.0) (171.7) --------- --------- --------- Net Cash Used by Financing Activities (321.8) (395.0) (498.3) --------- --------- --------- Net Increase (Decrease) In Cash and Cash Equivalents 80.0 3.0 (4.4) Cash and Cash Equivalents at Beginning of Year 6.0 3.0 7.4 --------- --------- --------- Cash and Cash Equivalents at End of Year $ 86.0 $ 6.0 $ 3.0 ========= ========= ========= Cash paid for interest (net of capitalized interest of $.7, $.5 and $.6) and income taxes: Interest (including nonutility subsidiary interest of $58.4, $71.5 and $83.4) $ 198.6 $ 202.8 $ 217.0 Income taxes (including nonutility subsidiary) $ 68.9 $ 53.1 $ 28.6 42
Consolidated Statements of Comprehensive Income Potomac Electric Power Company and Subsidiaries
- -------------------------------------------------------------------------------------------------- For the year ended December 31, 1998 1997 1996 - -------------------------------------------------------------------------------------------------- (Millions of Dollars) Net Income $ 226.3 $ 181.8 $ 237.0 Other Comprehensive Income (Loss): Unrealized gain (loss) on marketable securities 5.4 18.9 (3.3) Less: Reclassification adjustment for gain included in net income 3.4 10.6 5.6 --------- --------- --------- Other Comprehensive Income (Loss), Before Tax 2.0 8.3 (8.9) Income Tax Expense (Benefit) 0.7 2.9 (3.1) --------- --------- --------- Total Other Comprehensive Income (Loss), Net of Tax 1.3 5.4 (5.8) --------- --------- --------- Total Comprehensive Income $ 227.6 $ 187.2 $ 231.2 ========= ========= ========= 43
Notes to Consolidated Financial Statements - ------------------------------------------ (1) Organization and Summary of Significant Accounting Policies ----------------------------------------------------------- Potomac Electric Power Company (the Company, PEPCO) is engaged in the generation, transmission, distribution and sale of electric energy in the Washington, D.C. metropolitan area. The Company's retail service territory includes all of the District of Columbia and major portions of Montgomery and Prince George's counties in suburban Maryland. In addition, the Company supplies electricity, at wholesale, under a full-requirements agreement with Southern Maryland Electric Cooperative, Inc. (SMECO). See Note (13) Commitments and Contingencies for a further discussion. The Company also delivers economy energy to the Pennsylvania-New Jersey-Maryland Interconnection LLC (PJM) of which the Company is a member. PJM is composed of more than 100 electric utilities, independent power producers, power marketers, cooperatives and municipals which operate on a fully integrated basis. Potomac Capital Investment Corporation (PCI), a wholly owned subsidiary of the Company, was formed in 1983 to provide a vehicle to conduct the Company's ongoing nonutility investment programs and operating businesses. During 1998, PCI's principal new business activity has been the development and expansion of operating businesses in the competitive markets for energy and telecommunications products and services. PCI's principal financial investments are in aircraft and power generation equipment, equipment leasing and marketable securities, primarily preferred stock with mandatory redemption features. In addition, PCI has investments in real estate properties in the Washington, D.C. metropolitan area. Potomac Electric Power Company Trust I (Trust), a Delaware statutory business trust and a wholly owned subsidiary of the Company, was established in April 1998. The Trust exists for the exclusive purposes of (i) issuing Trust securities representing undivided beneficial interests in the assets of the Trust, (ii) investing the gross proceeds from the sale of the Trust Securities in Junior Subordinated Deferrable Interest Debentures issued by the Company, and (iii) engaging only in other activities as necessary or incidental to the foregoing. See Note (9) Redeemable Serial Preferred Stock and Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust for a further discussion. The Company's utility operations are regulated by the Maryland and District of Columbia public service commissions and its wholesale business by the Federal Energy Regulatory Commission (FERC). The Company complies with the Uniform System of Accounts prescribed by the FERC and adopted by the Maryland and District of Columbia regulatory commissions. 44 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 revenue and expenses during the reporting period. Actual results could differ from those estimates and assumptions. Certain prior year amounts have been reclassified to conform to the current year presentation. A summary of the Company's significant accounting policies is as follows. Principles of Consolidation - --------------------------- The consolidated financial statements include the financial results of the Company and its wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. Total Revenue - ------------- Revenue is accrued for service rendered but unbilled as of the end of each month. The Company includes in revenue the amounts received for sales of energy, and resales of purchased energy, to other utilities and to power marketers. Amounts received for such interchange deliveries are a component of the Company's fuel rates. In each jurisdiction, the Company's rate schedules include fuel rates. The fuel rate provisions are designed to provide for separately stated fuel billings which cover applicable net fuel and interchange costs, purchased capacity in the District of Columbia, and emission allowance costs in the Company's retail jurisdictions, or changes in the applicable costs from levels incorporated in base rates. Differences between applicable net costs incurred and fuel rate revenue billed in any given period are accounted for as other current assets or other current liabilities in those cases where specific provision has been made by the appropriate regulatory commission for the resolution of such differences within one year. Where no such provision has been made, the differences are accounted for as other deferred charges or other deferred credits pending regulatory determination. 45 Leasing Transactions - -------------------- Income from PCI investments in direct finance and leveraged lease transactions, in which PCI is an equity participant, is reported using the financing method. In accordance with the financing method, investments in leased property are recorded as a receivable from the lessee to be recovered through the collection of future rentals. For direct finance leases, unearned income is amortized to income over the lease term at a constant rate of return on the net investment. Income, including investment tax credits on leveraged equipment leases, is recognized over the life of the lease at a level rate of return on the positive net investment. PCI investments in equipment under operating leases are stated at cost less accumulated depreciation. Depreciation is recorded on a straight line basis over the equipment's estimated useful life. Property and Plant - ------------------ The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized. Such cost includes material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits. The original cost of depreciable units of plant retired, together with the cost of removal, net of salvage, is charged to accumulated depreciation. Routine repairs and maintenance are charged to operating expenses as incurred. The Company uses separate depreciation rates for each electric plant account. The rates, which vary from jurisdiction to jurisdiction, were equivalent to a system-wide composite depreciation rate of approximately 3.1% for 1998, 1997 and 1996. Conservation - ------------ In general, the Company accounts for conservation expenditures in connection with its DSM program as a deferred charge. These program costs are amortized as they are included in rates charged to customers. In the District of Columbia, these costs are amortized over 10 years with an accrued return on unamortized costs. In Maryland program costs have been amortized over a five year period. Future DSM expenditures in Maryland will be recovered over progressively shorter periods so that all expenditures will be fully recovered by December 31, 2002. Unamortized 46 conservation costs totaled $59.8 million in Maryland and $137.7 million in the District of Columbia at December 31, 1998, and $81.9 million in Maryland and $139.6 million in the District of Columbia at December 31, 1997. Allowance for Funds Used During Construction and Capital Cost Recovery Factor - -------------------------------------------------------- In general, the Company capitalizes AFUDC with respect to investments in Construction Work in Progress with the exception of expenditures required to comply with federal, state or local environmental regulations (pollution control projects), which are included in rate base without capitalization of AFUDC. The jurisdictional AFUDC capitalization rates are determined as prescribed by the FERC. The effective capitalization rates were approximately 7.5% in 1998, 7.6% in 1997 and 7.4% in 1996, compounded semiannually. In Maryland, the Company accrues a CCRF on the retail jurisdictional portion of certain pollution control expenditures related to compliance with the CAA. The base for calculating this return is the amount by which the Maryland jurisdictional CAA expenditure balance exceeds the CAA balance being recovered in base rates. The CCRF rate for Maryland is 9%. In the District of Columbia, the carrying costs of CAA expenditures not in rate base are recovered through a base rate surcharge. Amortization of Debt Issuance and Reacquisition Costs - ----------------------------------------------------- The Company defers and amortizes expenses incurred in connection with the issuance of long-term debt, including premiums and discounts associated with such debt, over the lives of the respective issues. Costs associated with the reacquisition of debt are also deferred and amortized over the lives of the new issues. Nonutility Subsidiary Receivables - --------------------------------- PCI continuously monitors its receivables and establishes an allowance for doubtful accounts against its notes receivable, when deemed appropriate, on a specific identification basis. The direct write-off method is used when trade receivables are deemed uncollectible. 47 Cash and Cash Equivalents - ------------------------- For purposes of the consolidated financial statements, cash and cash equivalents include cash on hand, money market funds and commercial paper with original maturities of three months or less. New Accounting Standards - ------------------------ In 1998, the Company implemented SFAS No. 130 entitled "Reporting Comprehensive Income, SFAS No. 131 entitled "Disclosures about Segments of an Enterprise and Related Information," and SFAS No. 132 entitled "Employers Disclosures about Pensions and Other Postretirement Benefits." In June 1998, the FASB issued SFAS No. 133 entitled, "Accounting for Derivative Instruments and Hedging Activities," which is effective for all fiscal quarters of fiscal years beginning after June 15, 1999. The statement establishes accounting and reporting standards for derivative instruments and for hedging activities. Additionally, the Emerging Issues Task Force has issued Issue 98-10 "Accounting for Energy Trading and Risk Management Activities." Presently, the Company's use of derivatives and hedging activities is not significant. The Company believes that the adoption of SFAS No. 133 will not have a material impact on the Company's financial position or results of operations. In March 1998, the Accounting Standards Executive Committee of the American Institute of Certified Public Accountants issued Statement of Position (SOP) 98-1 entitled "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use." This pronouncement will become effective January 1, 1999. The Company does not believe that the SOP will have a material impact on the Company's financial position or results of operations. 48 (2) Total Revenue ------------- Total revenue for each year ended December 31, was comprised as shown below. - ----------------------------------------------------------------- 1998 1997 1996 -------------------------------------------------- Amount % Amount % Amount % - ----------------------------------------------------------------- (Millions of Dollars) Sales of Electricity Residential $ 566.8 30.3 $ 524.7 29.2 $ 548.1 30.1 Commercial 876.7 46.8 851.4 47.3 852.5 46.7 U.S. Government 253.5 13.5 249.3 13.9 250.4 13.7 D.C. Government 51.5 2.8 51.1 2.8 51.6 2.8 Wholesale (primarily SMECO) 124.2 6.6 123.3 6.8 122.2 6.7 -------- ----- -------- ----- -------- ----- Total 1,872.7 100.0 1,799.8 100.0 1,824.8 100.0 ===== ===== ===== Other electric revenue 13.4 11.0 10.0 --------- -------- -------- Operating revenue 1,886.1 1,810.8 1,834.8 Interchange deliveries 177.8 52.7 175.5 --------- -------- -------- Total Revenue $2,063.9 $1,863.5 $2,010.3 ========= ======== ======== - ----------------------------------------------------------------- Sales of electricity include base rate revenue and fuel rate revenue. Fuel rate revenue was $518.1 million in 1998, $509.1 million in 1997 and $521.9 million in 1996. The Company's Maryland fuel rate is based on historical net fuel, interchange and emission allowance costs and does not include capacity costs associated with power purchases. The zero-based rate may not be changed without prior approval of the Maryland Public Service Commission. Application to the Commission for an increase in the rate may only be made when the currently calculated fuel rate, based on the most recent actual 49 net fuel, interchange and emission allowance costs, exceeds the currently effective fuel rate by more than 5%. If the currently calculated fuel rate is more than 5% below the currently effective fuel rate, the Company must apply to the Commission for a fuel rate reduction. The District of Columbia fuel rate is based upon an average of historical and projected net fuel, net interchange, emission allowance costs and purchased capacity net of capacity sales, and is adjusted monthly to reflect changes in such costs. Interchange deliveries include transactions in the bilateral energy sales marketplace, where the Company's wholesale power sales tariff allows both sales from Company-owned generation and sales of energy purchased by the Company from other market participants. The benefits derived from interchange deliveries are passed back to customers as a component of the Company's fuel rates. (3) Pensions and Other Postretirement and Postemployment Benefits ---------------------------------------------------- The Company's General Retirement Program (Program), a noncontributory defined benefit program, covers substantially all full-time employees of the Company and PCI. The Program provides for benefits to be paid to eligible employees at retirement based primarily upon years of service with the Company and their compensation rates for the three years preceding retirement. Annual provisions for accrued pension cost are based upon independent actuarial valuations. The Company's policy is to fund accrued pension costs. In addition to providing pension benefits, the Company provides certain health care and life insurance benefits for retired employees and inactive employees covered by disability plans. Health maintenance organization arrangements are available, or a health care plan pays stated percentages of most necessary medical expenses incurred by these employees, after subtracting payments by Medicare or other providers and after a stated deductible has been met. The life insurance plan pays benefits based on base salary at the time of retirement and age at the date of death. Participants become eligible for the benefits of these plans if they retire under the provisions of the Company's Program with 10 years of service or become inactive employees under the Company's disability plans. The Company is amortizing the unrecognized transition obligation measured at January 1, 1993, over a 20-year period. 50 Pension expense included in net income was $9.3 million in 1998, $11.6 million in 1997 and $14.2 million in 1996. Postretirement benefit expense included in net income was $12.6 million, $11.1 million and $10.9 million in 1998, 1997 and 1996, respectively. The components of net periodic benefit cost were computed as follows. - ----------------------------------------------------------------- Pension Benefits 1998 1997 1996 - ----------------------------------------------------------------- (Millions of Dollars) Components of net periodic benefit cost Service cost $13.0 $ 11.4 $ 11.4 Interest cost 33.9 32.4 30.6 Expected return on plan assets (41.2) (35.8) (31.7) Amortization of prior service cost 1.4 1.4 1.4 Recognized actuarial loss 2.2 2.2 2.5 ------ ------ ------ Net period benefit cost $ 9.3 $ 11.6 $ 14.2 ====== ====== ====== - ----------------------------------------------------------------- Other Benefits 1998 1997 1996 - ----------------------------------------------------------------- (Millions of Dollars) Components of net periodic benefit cost Service cost $ 4.0 $ 3.6 $ 2.8 Interest cost 5.8 5.3 5.3 Expected return on plan assets (1.5) (1.4) (1.0) Recognized actuarial loss 4.3 3.6 3.8 ------ ------ ------ Net period benefit cost $ 12.6 $ 11.1 $ 10.9 ====== ====== ====== 51 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The assumed health care cost trend rate used to measure the expected cost benefits covered by the plan is 6.5%. This rate is expected to decline to 5.5% over the next two-year period. A one- percentage point change in the assumed health care cost trend rates would have the following effects for fiscal year 1998: - ----------------------------------------------------------------- 1-Percentage- 1-Percentage- Point Increase Point Decrease -------------- -------------- (Millions of Dollars) Effect on total of service and interest cost components $ .8 $ (.7) Effect on postretirement benefit obligation $5.0 $(4.4) - ----------------------------------------------------------------- 52 Pension program assets are stated at fair value and were comprised of approximately 43% and 47% of cash equivalents and fixed income investments and the balance in equity investments at December 31, 1998 and 1997, respectively. The following table sets forth the Program's funded status and amounts included in Deferred Charges - Other on the Consolidated Balance Sheets. - ----------------------------------------------------------------- Pension Benefits 1998 1997 - ----------------------------------------------------------------- (Millions of Dollars) Funded status $(31.4) $(26.8) Unrecognized actuarial loss 95.1 77.7 Unrecognized prior service cost 12.1 13.5 ------ ------ Prepaid benefit cost $ 75.8 $ 64.4 ====== ====== Weighted average assumptions as of December 31 Discount rate 6.5% 7.0% Expected return on plan assets 9.0% 9.0% Rate of compensation increase 3.75% 4.0% - ----------------------------------------------------------------- Other Benefits 1998 1997 - ----------------------------------------------------------------- (Millions of Dollars) Funded status $(77.8) $(68.4) Unrecognized actuarial loss 44.2 36.7 Unrecognized prior service cost 29.5 31.6 ------ ------ Prepaid (Accrued) benefit cost $ (4.1) $ (.1) ====== ====== Weighted average assumptions as of December 31 Discount rate 6.5% 7.0% Expected return on plan assets 9.0% 9.0% Rate of compensation increase 3.75% 4.0% - ----------------------------------------------------------------- 53 The changes in benefit obligation and fair value of plan assets are presented in the following table. - ----------------------------------------------------------------- Pension Benefits 1998 1997 - ----------------------------------------------------------------- (Millions of Dollars) Change in benefit obligation Benefit obligation at beginning of year $ 495.6 $ 438.1 Service cost 13.0 11.4 Interest cost 33.9 32.4 Actuarial loss 25.1 39.1 Benefits paid (26.0) (25.4) ------- ------- Benefit obligation at end of year $ 541.6 $ 495.6 ======= ======= Accumulated benefit obligation at December 31, $ 467.4 $ 413.5 ======= ======= Change in fair value of plan assets Fair value of plan assets at beginning of year $ 468.8 $ 402.5 Actual return on plan assets 49.1 64.2 Company contributions 20.0 27.5 Benefits paid (27.7) (25.4) ------- ------- Fair value of plan assets at end of year $ 510.2 $ 468.8 ======= ======= - ----------------------------------------------------------------- 54 - ----------------------------------------------------------------- Other Benefits 1998 1997 - ----------------------------------------------------------------- (Millions of Dollars) Change in benefit obligation Benefit obligation at beginning of year $ 82.0 $ 73.1 Service cost 4.0 3.6 Interest cost 5.8 5.3 Actuarial loss 7.9 5.4 Benefits paid (6.3) (5.4) ------ ------ Benefit obligation at end of year $ 93.4 $ 82.0 ====== ====== Change in fair value of plan assets Fair value of plan assets at beginning of year $ 13.6 $ 9.8 Actual return on plan assets 1.7 2.7 Company contributions 4.7 3.6 Benefits paid (4.4) (2.5) ------ ------ Fair value of plan assets at end of year $ 15.6 $ 13.6 ====== ====== - ----------------------------------------------------------------- The Company also sponsors defined contribution savings plans covering all eligible employees. Under these plans, the Company makes contributions on behalf of participants. Company contributions to the plans totaled $5.8 million in 1998, and $6 million in 1997 and 1996. In January 1998 and 1997, the Company funded the 1998 and 1997 portions of its estimated liability for postretirement medical and life insurance costs through the use of an Internal Revenue Code (IRC) 401 (h) account, within the Company's pension plan, and an IRC 501 (c)(9) Voluntary Employee Beneficiary Association (VEBA). The Company plans to fund the 401(h) account and the VEBA annually. In January 1999, the 1999 portion of the Company's estimated liability will be funded. Assets were comprised of cash equivalents, fixed income investments and equity investments. 55 (4) Income Taxes ------------ The provisions for income taxes, reconciliation of consolidated income tax expense and components of consolidated deferred tax liabilities (assets) are set forth below.
Provisions for Income Taxes - --------------------------- - ----------------------------------------------------------------------------------------------- 1998 1997 1996 - ----------------------------------------------------------------------------------------------- (Millions of Dollars) Utility current tax expense Federal $ 95.8 $ 32.2 47.2 State and local 12.1 4.7 6.3 -------- -------- ------- Total utility current tax expense 107.9 36.9 53.5 -------- -------- ------- Utility deferred tax expense Federal 22.4 56.3 74.7 State and local 4.3 7.9 10.4 Investment tax credits (3.6) (3.6) (3.6) -------- -------- ------- Total utility deferred tax expense 23.1 60.6 81.5 -------- -------- ------- Total utility income tax expense 131.0 97.5 135.0 -------- -------- ------- Nonutility subsidiary current tax expense Federal 15.4 30.4 (18.2) Nonutility subsidiary deferred tax expense Federal (24.1) (62.3) (36.4) -------- -------- ------- Total nonutility subsidiary income tax expense (8.7) (31.9) (54.6) -------- -------- ------- Total consolidated income tax expense 122.3 65.6 80.4 Income taxes included in other income (8.2) (52.1) (53.7) -------- -------- ------- Income taxes included in utility operating expenses $ 130.5 $ 117.7 134.1 ======== ======== ======= 56
Reconciliation of Consolidated Income Tax Expense - ------------------------------------------------- - ----------------------------------------------------------------------------------------------- 1998 1997 1996 - ----------------------------------------------------------------------------------------------- (Millions of Dollars) Income before income taxes $ 348.6 $ 247.4 317.4 ======== ======== ======= Utility income tax at federal statutory rate $ 119.8 $ 91.8 124.3 Increases (decreases) resulting from Depreciation 10.9 10.9 9.9 Removal costs (6.0) (5.9) (3.6) Allowance for funds used during construction 0.5 0.9 0.7 Other (0.9) (4.5) (3.1) State income taxes, net of federal effect 10.7 8.2 10.7 Tax credits (4.0) (3.9) (3.9) -------- -------- ------- Total utility income tax expense 131.0 97.5 135.0 -------- -------- ------- Nonutility subsidiary income tax at federal statutory rate 2.2 (5.2) (13.2) Increases (decreases) resulting from Dividends received deduction (4.4) (5.4) (7.1) Reversal of previously accrued deferred taxes (1.0) (10.1) (30.8) Other (5.5) (11.2) (3.5) -------- -------- ------- Total nonutility subsidiary income tax expense (8.7) (31.9) (54.6) -------- -------- ------- Total consolidated income tax expense 122.3 65.6 80.4 Income taxes included in other income (8.2) (52.1) (53.7) -------- -------- ------- Income taxes included in utility operating expenses $ 130.5 $ 117.7 134.1 ======== ======== =======
Components of Consolidated Deferred Tax Liabilities (Assets) - ------------------------------------------------------------ At December 31, -------------------- 1998 1997 -------------------- (Millions of Dollars) Utility deferred tax liabilities (assets) Depreciation and other book to tax basis differences $ 891.6 $ 869.3 Rapid amortization of certified pollution control facilities 27.2 25.4 Deferred taxes on amounts to be collected through future rates 88.0 90.2 Property taxes 12.9 13.5 Deferred fuel (9.7) (7.4) Prepayment premium on debt retirement 18.9 20.0 Deferred investment tax credit (20.3) (21.7) Contributions in aid of construction (32.0) (30.1) Contributions to pension plan 22.1 18.2 Conservation costs (demand side management) 49.4 48.0 Other 19.7 21.8 -------- -------- Total utility deferred tax liabilities, net 1,067.8 1,047.2 Current portion of utility deferred tax liabilities (included in Other Current Liabilities) 18.6 17.9 -------- -------- Total utility deferred tax liabilities, net - non-current $1,049.2 $1,029.3 ======== ======== Nonutility subsidiary deferred tax (assets) liabilities Finance leases $ 134.3 $ 119.4 Operating leases 5.0 28.8 Alternative minimum tax (79.9) (97.1) Assets with a tax basis greater than book basis (46.0) - Other (75.2) (50.9) -------- -------- Total nonutility subsidiary deferred tax (assets) liabilities, net $ (61.8) $ 0.2 ======== ======== 57
The utility net deferred tax liability represents the tax effect, at presently enacted tax rates, of temporary differences between the financial statement and tax bases of assets and liabilities. The portion of the utility net deferred tax liability applicable to utility operations, which has not been reflected in current service rates, represents income taxes recoverable through future rates, net and is recorded as a Deferred Charge on the balance sheet. No valuation allowance for deferred tax assets was required or recorded at December 31, 1998 and 1997. The Tax Reform Act of 1986 repealed the Investment Tax Credit (ITC) for property placed in service after December 31, 1985, except for certain transition property. ITC previously earned on utility property continues to be normalized over the remaining service lives of the related assets. The Company and PCI file a consolidated federal income tax return. The Company's federal income tax liabilities for all years through 1995 have been finally determined. The Company is of the opinion that the final settlement of its federal income tax liabilities for subsequent years will not have a material adverse effect on its financial position or results of operation. (5) Other Taxes ----------- Taxes, other than income taxes, charged to utility operating expenses for each period are shown below. - ----------------------------------------------------------------- 1998 1997 1996 - ----------------------------------------------------------------- (Millions of Dollars) Gross receipts $ 98.4 $ 95.8 $ 96.1 Property 71.0 71.4 69.2 Payroll 10.9 10.5 10.7 County fuel-energy 15.8 15.4 15.4 Environmental, use and other 8.3 8.6 9.0 ------ ------ ------ $204.4 $201.7 $200.4 ====== ====== ====== - ----------------------------------------------------------------- 58 (6) Jointly Owned Generating Facilities ----------------------------------- The Company owns a 9.72% undivided interest in the Conemaugh Generating Station located near Johnstown, Pennsylvania, consisting of two baseload units totaling 1,700 megawatts. The Company and other utilities own the station as tenants in common and share costs and output in proportion to their ownership shares. Each owner has arranged its own financing relating to its share of the facility. In 1997, the owners collectively arranged for long-term tax-exempt financing, pursuant to an agreement with the Indiana County Industrial Development Authority relating to certain pollution control facilities constructed at the Conemaugh Station. The Company's share of this financing totaled $8.1 million. The Company's share of the operating expenses of the station is included in the Consolidated Statements of Earnings. The Company's investment in the Conemaugh facility of $90.6 million at December 31, 1998, and $89.9 million at December 31, 1997, includes $.3 million of Construction Work in Progress. 59 (7) Common Equity Changes in common stock, premium on stock, accumulated other comprehensive income and retained income are summarized below. - ----------------------------------------------------------------------------------------------------------- Accumulated Other Common Stock Premium Comprehensive Retained Shares Par Value on Stock Income Income
- ----------------------------------------------------------------------------------------------------------- (Millions of Dollars) Balance, December 31, 1995 118,494,577 $ 118.5 $ 1,025.1 $ 6.9 $ 735.4 Net income before net earnings from nonutility subsidiary - - - - 220.1 Nonutility subsidiary: Net earnings - - - - 16.9 Other comprehensive loss - - - (5.8) - Dividends: Preferred stock - - - - (16.6) Common stock - - - - (196.6) Conversion of preferred stock 3,239 - - - - Conversion of debentures 2,221 - 0.1 - - ----------- ---------- ---------- -------------- - --------- Balance, December 31, 1996 118,500,037 118.5 1,025.2 1.1 759.2 Net income before net earnings from nonutility subsidiary - - - - 164.7 Nonutility subsidiary: Net earnings - - - - 17.1 Other comprehensive income - - - 5.4 - Dividends: Preferred stock - - - - (16.5) Common stock - - - - (196.7) Conversion of preferred stock 854 - - - - ----------- ---------- ---------- -------------- - --------- Balance, December 31, 1997 118,500,891 118.5 1,025.2 6.5 727.8 Net income before net earnings from nonutility subsidiary - - - - 211.2 Nonutility subsidiary: Net earnings - - - - 15.1 Other comprehensive income - - - 1.3 - Dividends: Preferred stock - - - - (11.4) Common stock - - - - (196.6) Conversion of preferred stock 26,396 - 0.1 - - Redemption premium on preferred stock - - - - (6.6) ----------- ---------- ---------- -------------- - --------- Balance, December 31, 1998 118,527,287 $ 118.5 $ 1,025.3 $ 7.8 $ 739.5 =========== ========== ========== ============== = ========= Represents unrealized gains (losses) on marketable securities of nonutility subsidiary. 60
The Company's Shareholder Dividend Reinvestment Plan (DRP) provides that shares of common stock purchased through the plan may be original issue shares or, at the option of the Company, shares purchased in the open market. The DRP permits additional cash investments by plan participants limited to one investment per month of not less than $25 and not more than $5,000. As of December 31, 1998, 2,769,412 and 3,392,500 shares of common stock were reserved for issuance upon the conversion of the 7% and 5% convertible debentures, respectively, 2,324,721 shares were reserved for issuance under the DRP and 1,221,624 shares were reserved for issuance under the Employee Savings Plans. Certain provisions of the Company's corporate charter, relating to preferred and preference stock, would impose restrictions on the payment of dividends under certain circumstances. No portion of retained income was so restricted at December 31, 1998. 61 Calculations of Earnings Per Common Share - ----------------------------------------- Reconciliations of the numerator and denominator for basic and diluted earnings per common share are shown below.
- ------------------------------------------------------------------------------------------------------------ For the year ended December 31, 1998 1997 1996 - ------------------------------------------------------------------------------------------------------------ (Millions, except Per Share Data) Income (Numerator): Earnings applicable to common stock $ 208.3 $ 165.3 $ 220.4 Add: Dividends paid or accrued on Convertible Preferred Stock - - - Interest paid or accrued on Convertible Debentures, net of related taxes 6.3 6.3 6.4 ---------- ---------- ---------- Earnings applicable to common stock, assuming conversion of convertible securities $ 214.6 $ 171.6 $ 226.8 ========== ========== ========== Shares (Denominator): Average shares outstanding for computation of basic earnings per common share 118.5 118.5 118.5 ========== ========== ========== Average shares outstanding for diluted computation: Average shares outstanding 118.5 118.5 118.5 Additional shares resulting from: Conversion of Convertible Debentures 5.7 5.8 5.8 ---------- ---------- ---------- Average shares outstanding for computation of diluted earnings per common share 124.2 124.3 124.3 ========== ========== ========== Basic earnings per common share $1.76 $1.39 $1.86 Diluted earnings per common share $1.73 $1.38 $1.82 62
(8) Serial Preferred Stock ---------------------- The Company has authorized 8,750,000 shares of cumulative $50 par value Serial Preferred Stock. At December 31, 1998 and 1997, there were outstanding 3,000,000 shares and 5,345,499 shares, respectively. The various series of Serial Preferred Stock outstanding [excluding 1,000,000 shares of Redeemable Serial Preferred Stock - See Note (9)] and the per share redemption price at which each series may be called by the Company are as follows. - ----------------------------------------------------------------- Redemption December 31, Price 1998 1997 - ----------------------------------------------------------------- (Millions of Dollars) $2.44 Series of 1957, 300,000 shares $51.00 $ 15.0 $ 15.0 $2.46 Series of 1958, 300,000 shares $51.00 15.0 15.0 $2.28 Series of 1965, 400,000 shares $51.00 20.0 20.0 $3.82 Series of 1969, none and 500,000 shares, respectively $51.00 - 25.0 $2.44 Convertible Series of 1966, none and 5,803 shares, respectively $50.00 - .3 Auction Series A, 1,000,000 shares $50.00 50.0 50.0 ------ ------ $100.0 $125.3 ====== ====== - ----------------------------------------------------------------- The Company on March 1, 1998, redeemed all remaining shares of Serial Preferred Stock, $2.44 Convertible Series of 1966. Prior to the redemption, the $2.44 Convertible Series was convertible into common stock of the Company. The number of shares of this series converted into common stock was 4,525 shares in 1998, 147 shares in 1997 and 556 shares in 1996. In addition, on June 1, 1998, the Company redeemed all of the 500,000 shares of Serial Preferred Stock, $3.82 Series of 1969. Dividends on the Serial Preferred Stock, Auction Series A, are based on the rate determined by auction procedures prior to each dividend period. The maximum rate can range from 110% to 200% of the applicable "AA" Composite Commercial Paper Rate. The annual dividend rate is 4.2% ($2.10) for the period December 1, 1998 through February 28, 1999. The average annual dividend rates were 4.136% ($2.068) in 1998 and 4.221% ($2.1105) in 1997. 63 (9) Redeemable Serial Preferred Stock and Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust --------------------------------------------------------- The outstanding series of $50 par value Redeemable Serial Preferred Stock are shown below. - ----------------------------------------------------------------- December 31, 1998 1997 - ----------------------------------------------------------------- (Millions of Dollars) $3.37 Series of 1987, none and 839,696 shares, respectively $ - $ 42.0 $3.89 Series of 1991, none and 1,000,000 shares, respectively - 50.0 $3.40 Series of 1992, 1,000,000 shares 50.0 50.0 ------ ------ 50.0 142.0 Redemption Requirement due within one year - (1.0) ------ ------ $ 50.0 $141.0 ====== ====== - ---------------------------------------------------------------- On May 19, 1998, Potomac Electric Power Company Trust I (see Note (1) Organization and Summary of Significant Accounting Policies) issued $125 million of 7-3/8% Trust Originated Preferred Securities (TOPrS). The proceeds from the sale of the TOPrS to the public and from the sale of the common securities of the Trust to the Company were used by the Trust to purchase from the Company $128.9 million of 7-3/8% Junior Subordinated Deferrable Interest Debentures, due June 1, 2038 (Junior Subordinated Debentures). The sole assets of the Trust are the Junior Subordinated Debentures. The Trust will use interest payments received on the Junior Subordinated Debentures to make quarterly cash distributions on the TOPrS. Accrued and unpaid distributions on the TOPrS, as well as payment of the redemption price upon the redemption and of the liquidation amount upon the voluntary or involuntary dissolution, winding-up or termination of the Trust, to the extent such funds are held by the Trust, are guaranteed by the Company (Guarantee). The Guarantee, when taken together with the Company's obligation under the Junior Subordinated Debentures and the Indenture for the Junior Subordinated Debentures, and the Company's obligations under the declaration of Trust for the TOPrS, including its obligations to pay costs, expenses, debts and liabilities of the Trust, provides a full and unconditional guarantee by the Company on a subordinated basis of the Trust obligations. Proceeds from the 64 sale of the Junior Subordinated Debentures to the Trust were used by the Company to redeem the Serial Preferred Stock, $3.82 Series of 1969, $3.37 Series of 1987 and $3.89 Series of 1991 on June 1, 1998. The shares of the $3.40 (6.80%) Series are subject to mandatory redemption, at par, through the operation of a sinking fund which will redeem 50,000 shares annually, beginning September 1, 2002, with the remaining shares redeemed on September 1, 2007. The shares are not redeemable prior to September 1, 2002; thereafter, the shares are redeemable at par. In the event of default with respect to dividends, or sinking fund or other redemption requirements relating to the serial preferred stock, no dividends may be paid, nor any other distribution made, on common stock. Payments of dividends on all series of serial preferred or preference stock, including series which are redeemable, must be made concurrently. The sinking fund requirements through 2003 with respect to the Redeemable Serial Preferred Stock are $2.5 million in 2002 and 2003. 65 (10) Long-Term Debt
Details of long-term debt are shown below. - ---------------------------------------------------------------------------------------------------- Interest December 31, Rate Maturity 1998 1997 - ---------------------------------------------------------------------------------------------------- (Millions of Dollars) First Mortgage Bonds Fixed Rate Series: 4-3/8% February 15, 1998 $ - $ 50.0 4-1/2% May 15, 1999 45.0 45.0 9% April 15, 2000 100.0 100.0 5-1/8% April 1, 2001 15.0 15.0 5-7/8% May 1, 2002 35.0 35.0 6-5/8% February 15, 2003 40.0 40.0 5-5/8% October 15, 2003 50.0 50.0 6-1/2% September 15, 2005 100.0 100.0 6-1/4% October 15, 2007; PUT date October 15, 2004 175.0 175.0 6-1/2% March 15, 2008 78.0 78.0 5-7/8% October 15, 2008 50.0 50.0 5-3/4% March 15, 2010 16.0 16.0 9% June 1, 2021 100.0 100.0 6% September 1, 2022 30.0 30.0 6-3/8% January 15, 2023 37.0 37.0 7-1/4% July 1, 2023 100.0 100.0 6-7/8% September 1, 2023 100.0 100.0 5-3/8% February 15, 2024 42.5 42.5 5-3/8% February 15, 2024 38.3 38.3 6-7/8% October 15, 2024 75.0 75.0 7-3/8% September 15, 2025 75.0 75.0 8-1/2% May 15, 2027 75.0 75.0 7-1/2% March 15, 2028 40.0 40.0 Variable Rate Series: Adjustable rate December 1, 2001 50.0 50.0 --------- --------- Total First Mortgage Bonds 1,466.8 1,516.8 Convertible Debentures 5% September 1, 2002 115.0 115.0 7% January 15, 2018 62.8 63.9 Medium-Term Notes Fixed Rate Series: 6.53% December 17, 2001 100.0 100.0 7.46% to 7.60% January 2002 40.0 40.0 7.64% January 17, 2007 35.0 35.0 6.25% January 20, 2009 50.0 50.0 7% January 15, 2024 50.0 50.0 Variable Rate Series: Adjustable rate June 1, 2027 8.1 8.1 --------- --------- Total Utility Long-Term Debt 1,927.7 1,978.8 Net unamortized discount (23.5) (26.2) Current portion (45.2) (51.1) --------- --------- Net Utility Long-Term Debt $ 1,859.0 $ 1,901.5 ========= ========= Nonutility Subsidiary Long-Term Debt Varying rates through 2018 $ 716.9 $ 830.5 ========= ========= 66
Utility Long-Term Debt - ---------------------- The outstanding First Mortgage Bonds are secured by a lien on substantially all of the Company's property and plant. Additional bonds may be issued under the mortgage as amended and supplemented in compliance with the provisions of the indenture. In February 1998, the Company redeemed, at maturity, $50 million of 4-3/8% First Mortgage Bonds. The interest rate on the $50 million Adjustable Rate series First Mortgage Bonds is adjusted annually on December 1, based upon the 10-year "constant maturity" United States Treasury bond rate for the preceding three-month period ended October 31, plus a market based adjustment factor. Effective December 1, 1998, the applicable interest rate is 6.093%. The applicable interest rate was 7.38% at December 1, 1997, and 7.867% at December 1, 1996. The 7% Convertible Debentures are convertible into shares of common stock at a conversion price of $27 per share. The 5% Convertible Debentures are convertible into shares of common stock at a conversion rate of 29-1/2 shares for each $1,000 principal amount. The aggregate amounts of maturities for the Company's long- term debt outstanding at December 31, 1998, are $45.2 million in 1999, $100 million in 2000, $165 million in 2001, $190 million in 2002 and $90 million in 2003. Nonutility Subsidiary Long-Term Debt - ------------------------------------ Long-term debt at December 31, 1998, consisted primarily of $697.6 million of recourse debt from institutional lenders maturing at various dates between 1999 and 2018. The interest rates of such borrowings ranged from 5% to 10.1%. The weighted average interest rate was 7.35% at December 31, 1998, 7.48% at December 31, 1997, and 7.44% at December 31, 1996. Annual aggregate principal repayments are $170 million in 1999, $147.5 million in 2000, $88.5 million in 2001, $93 million in 2002, and $134.5 million in 2003. 67 Long-term debt also includes $19.2 million of non-recourse debt, $11.7 million of which is secured by aircraft currently under operating lease. The debt is payable in monthly installments at rates of LIBOR (London Interbank Offered Rate) plus 1.25% with final maturity on March 15, 2002. Non-recourse debt of $7.5 million is related to PCI's majority-owned real estate partnerships and is based on a 30-year amortization period at a fixed rate of interest of 9.66%, with final maturity on October 1, 2011. 68 (11) Fair Value of Financial Instruments - ---------------------------------------- The estimated fair values of the Company's financial instruments at December 31, 1998, and 1997 are shown below.
- ------------------------------------------------------------------------------------------------------ December 31, 1998 1997 - ------------------------------------------------------------------------------------------------------ Carrying Fair Carrying Fair Amount Value Amount Value -------- -------- -------- -------- (Millions of Dollars) Utility Capitalization and Liabilities Serial preferred stock $ 100.0 95.4 125.3 127.3 Redeemable serial preferred stock $ 50.0 53.6 141.0 142.6 Company obligated mandatorily redeemable preferred securities of subsidiary trust which holds solely parent junior subordinated debentures $ 125.0 128.7 - - Long-term debt First mortgage bonds $1,408.4 1,489.5 1,452.4 1,507.5 Medium-term notes $ 281.3 304.5 281.2 289.9 Convertible debentures $ 169.3 175.2 167.9 172.4 Nonutility Subsidiary Assets Marketable securities $ 231.1 231.1 302.5 302.5 Notes receivable $ 25.5 22.4 23.1 19.5 Liabilities Long-term debt $ 716.9 729.2 830.5 841.0 - ------------------------------------------------------------------------------------------------------ 69
The methods and assumptions below were used to estimate, at December 31, 1998 and 1997, the fair value of each class of financial instruments shown above for which it is practicable to estimate that value. The fair value of the Company's Serial Preferred Stock, Redeemable Serial Preferred Stock and Company Obligated Mandatorily Redeemable Preferred Securities of Subsidiary Trust, excluding amounts due within one year, was based on quoted market prices or discounted cash flows using current rates of preferred stock with similar terms. The fair value of the Company's Long-term Debt, which includes First Mortgage Bonds, Medium-Term Notes and Convertible Debentures, excluding amounts due within one year, was based on the current market price, or for issues with no market price available, was based on discounted cash flows using current rates for similar issues with similar terms and remaining maturities. The fair value of PCI's Marketable Securities was based on quoted market prices. The fair value of PCI's Notes Receivable was based on discounted future cash flows using current rates and similar terms. The fair value of PCI's Long-term Debt, including non- recourse debt, was based on current rates offered to similar companies for debt with similar remaining maturities. The carrying amounts of all other financial instruments approximate fair value. (12) Short-Term Debt --------------- The Company's short-term financing requirements have been satisfied principally through the sale of commercial promissory notes. Interest rates for the Company's short-term financing during the year ranged from 4.6% to 6.3%. The Company maintains a minimum 100% line of credit back-up for its outstanding commercial promissory notes, which was unused during 1998, 1997 and 1996. 70 Nonutility Subsidiary Short-Term Notes Payable - ---------------------------------------------- The nonutility subsidiary's short-term financing requirements have been satisfied principally through the sale of commercial promissory notes. The nonutility subsidiary maintains a minimum 100% line of credit back-up, in the amount of $400 million, for its outstanding commercial promissory notes, which was unused during 1998, 1997 and 1996. (13) Commitments and Contingencies ----------------------------- Competition - ----------- The electric utility industry continues to be subjected to increasing competitive pressures, stemming from a combination of increasing independent power production and regulatory and legislative initiatives intended to increase bulk power competition, including the Energy Policy Act of 1992. Based on the regulatory framework in which it operates, the Company continues to apply the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" in accounting for its retail utility operations. SFAS No. 71 allows regulated entities, in appropriate circumstances, to establish regulatory assets and to defer the income statement impact of certain costs that are expected to be recovered in future rates. Deregulation of portions of the Company's business could, in the future, result in not meeting the rate recovery criteria for application of SFAS No. 71 for part or all of the business. If this were to occur in the transition to a more competitive industry, accounting standards of enterprises in general would apply which would entail the write-off of any previously deferred costs to results of operations. Regulatory assets include deferred income taxes, unamortized conservation costs and unamortized debt reacquisition costs recoverable through future rates. In addition, electric plant in service includes a regulatory asset related to capital leases, which are treated as operating leases for ratemaking purposes, of approximately $37 million and $29 million at December 31, 1998 and 1997, respectively. Under traditional regulation, utilities are provided an opportunity to earn a fair return on invested capital in exchange for a commitment to serve all customers within a designated service territory. To further the goal of providing universal access to safe and reliable electric service within this 71 regulated environment, regulatory decisions led to costs and commitments by utilities that may not be entirely recovered through market-based revenues in a competitive environment. Recovery and measurement of above-market, or "stranded" costs in a future competitive environment, will be subject to regulatory proceedings. Potential above-market costs include, but are not limited to, costs associated with generation facilities that are fixed and unavoidable, including future costs related to plant removal; above-market costs associated with purchased power obligations; and regulatory assets and obligations incurred in accordance with SFAS No. 71. The inability of the Company to recover its stranded costs fully could have a material adverse impact on the future earnings and cash flows of the Company, and may result in consequences including, but not limited to, increases in the cost of capital, increases in rates for transmission and distribution services, exposure to downgrades in credit ratings and involuntary layoffs of employees. The Company expects to be provided an opportunity to recover its stranded costs. Maryland - -------- In December 1997, the Maryland Public Service Commission issued orders that outlined steps toward a competitive electric generation market and established dates for the phased-in implementation of competition. Pursuant to the orders, competition will be phased in over a two-year period beginning July 1, 2000. Customers representing one-third of the electric load in a particular customer class will be able to choose their electric generation supplier at that time. On July 1, 2001, the eligible group increases to two-thirds in any one customer class, and all customers will then become eligible one year later. The Commission affirmed that Maryland utilities will be given the opportunity to recover verifiable and prudently incurred stranded costs which cannot be mitigated or reduced; proposals to establish a Competitive Transition Charge (CTC) for stranded cost recovery will be addressed in future proceedings. The Commission recommended that the Maryland legislature enact legislation to allow securitization of stranded costs, where it can be shown that this financing procedure will reduce costs for customers. The Commission ordered no mandatory rate reductions during the transition to competition, and applied the designation of default provider to the consumer's current utility. In addition, the Commission recognized the need for tax reform to "level the playing field" for Maryland utilities, and requested the Maryland legislature to enact the necessary legislation. Also, the Commission stated that fuel adjustment clauses are incompatible with the workings of a competitive generation market, and requested that legislation be enacted to discontinue use of fuel adjustment clauses in the future. Additionally, the Commission requested that legislation be enacted to permit price cap 72 regulation and materially depart from cost of service regulation with respect to the purchase and generation of electricity. The Commission proposed the establishment of statewide roundtables to address issues such as provision of metering and billing services, consumer protection and DSM, but did not propose any changes to the form of regulation currently applicable to the recovery of costs associated with the distribution of electricity. Moreover, the Commission did not order the divestiture or corporate unbundling of generating assets but indicated it will consider these options as part of its review of future market power studies required to be filed by Maryland electric utilities. In compliance with Commission orders, the Company filed on July 1, 1998, a quantification of its Maryland jurisdictional generating, purchased power and other costs that the Company projects would be stranded in a competitive market for generating services; a proposed method for recovering such stranded costs through a non-bypassable CTC; proposed unbundled rates for retail service; and a proposal to freeze retail rates from the time competition begins until January 2004 (collectively, the Filing). The Company made numerous assumptions in the Filing, including assumptions as to the outcome of the recently-concluded 1998 base rate case, the future price of electricity including fuel charges, future revenues, the costs of transmission and distribution, and service territory demographics, some or all of which may prove not to have been accurate. The Filing will be the subject of an adjudicatory proceeding which, in accordance with the terms of the Commission's orders, is expected to conclude in October 1999. As is its normal practice and is consistent with the Commission's procedural orders, the Company is also pursuing discussions with the other parties to the adjudicatory proceedings as to whether settlement of the issues is possible. Any such settlement would require the Commission's approval. The Commission's implementation process provides for a 15-month period to study the Filing. After that period, the Company will be required to file a restructuring plan in November 1999 which would take into account any restructuring legislation enacted by the General Assembly, as well as the outcome of the adjudicatory proceeding initiated by the Commission with respect to the Filing. Accordingly, the Filing does not constitute the Company's final restructuring plan. In connection with the Filing, the Company reiterated its position that absent appropriate enabling legislation by the Maryland General Assembly (which has yet to be enacted), the Commission lacks the legal authority to implement the plan filed by the Company, or any other restructuring plan providing for retail competition. 73 The Company has proposed separate unbundled rates for generation supply (i.e., the cost of producing power or buying it from third parties) and for electricity delivery (i.e., the cost of transmission and distribution of electricity to consumers). In the Filing, the Company's anticipated 1999 average price of 7.78 cents per kilowatt-hour breaks down into a supply charge of 4.60 cents and a delivery charge of 3.18 cents, which exceed the rates approved within the Company's recent Maryland base rate settlement agreement. As part of the Filing, the Company proposes that effective with the initial phase of competition, which is currently scheduled to commence July 1, 2000, both the supply and delivery components of the Company's retail prices will be frozen at then-existing levels until January 1, 2004. The Company also proposes to eliminate its fuel rate on July 1, 2000, and assume the risk of fuel cost increases after implementation of the restructuring plan until January 1, 2004, when the Company no longer has the obligation to supply electricity at the frozen rate. The only exceptions to the rate freeze would be for unexpected increases in taxes or new environmental requirements. After January 1, 2004, supply prices would be set by the competitive marketplace and delivery prices would be determined by regulators. For retail customers who do not wish to buy the supply portion of their electric service from a source other than the Company once they are free to do so, the Company proposes to provide both supply and delivery service at the frozen rates until January 1, 2004. For customers who enter the competitive supply market, the Company proposes to provide them with a "shopping credit" equal to the estimated market price for electricity. The shopping credit would terminate on January 1, 2004. Under the Company's proposal, the transition to customer choice, including recovery of stranded costs, would be made without any increase in prices to customers. Initially, prices would be held at the levels in effect when competition begins for customers who choose to buy both supply and delivery from the Company. During the freeze, an implicit non-bypassable CTC will be included in the frozen rate. After the end of the freeze in January 2004, all customers would pay, as part of their delivery charge, an explicit CTC that would successively decrease until 2021, when the last of the Company's pre-competition power purchase contracts ends. The proposed CTC will allow the Company the opportunity for full recovery of its prudent, non-mitigated stranded costs, as contemplated by the Commission in its December 1997 orders, without causing an increase in rates. In the Filing, the Company identifies stranded costs (the total economic value of previously expected regulatory earnings that will not be recovered in a deregulated energy market) having 74 a net after-tax present value of $600.4 million, which it proposes be securitized and recovered over the period 2000 through 2010. The $600.4 million is comprised of $319.8 million relating to generation assets, $242.6 million relating to power purchase contracts, and $38 million in other stranded costs. The Company proposes to recover additional stranded costs associated with its long-term Panda and SMECO power purchase contracts, having a present value of $42 million, over the period 2011 to 2021, which it does not propose be securitized. All stranded cost recovery would be accomplished through the non-bypassable CTC. The Company has also proposed a "true up" mechanism to update prospectively in July 2004 its stranded cost estimates taking into account changes in market price or other factors. The stranded costs in the Filing predominately relate to costs which are already included in the Company's rates. They have been approved by regulators as being appropriate to recover because they were found to have been prudently incurred to meet the Company's regulatory-era obligation to provide reliable service to everyone who wants it. The Company anticipates that these costs would be amortized to match the revenues collected by the CTC. As part of its plan, the Company proposes to securitize a portion of its stranded cost recovery and thereby achieve savings through a reduction in capital costs. If a competitive market for generation supply is implemented in Maryland, the Company believes that the Commission will follow through on its commitment to provide a fair opportunity for the Company to recover its prudently incurred stranded costs, and that the stranded costs identified by the Company in the filing will be determined to have been prudently incurred. The inability of the Company to recover fully its stranded costs could have a material adverse impact on the future earnings and cash flows of the Company, and may result in consequences including, but not limited to, increases in the cost of capital, increases in rates for transmission and distribution services, exposure to downgrades in credit ratings and involuntary layoffs of employees. On October 9, 1998, the Company and four other electric utilities operating in Maryland - Allegheny Power, Choptank Electric Cooperative, Inc., Conectiv and SMECO - filed separate appeals in Baltimore City Circuit Court seeking a judicial review of recent decisions by the Maryland Commission in which the Commission asserted its authority to restructure the electric utility industry without authorization from the Maryland State Legislature. The Company believes that the proper way to ensure progress is for the legislature, in its 1999 session, to grant the Commission authority to proceed. Accordingly, the utilities asked the court to defer action on the appeal until after completion of the 1999 legislative session, which began in January 1999. On December 18, 1998, the Company filed a motion for voluntary dismissal of its appeal without prejudice. The 75 Company's motion was filed pursuant to an agreement among Conectiv, Allegheny Power, SMECO, Choptank Electric Cooperative and the Maryland Public Service Commission that the Commission's restructuring orders were not "final orders" within the meaning of the law governing the powers of the Commission and, further, that the appeals challenging the Commission's authority to implement retail choice without enabling legislation could be filed after the Commission issues its order on the pending applications for rehearing filed by the Company and several other parties. All of the other utility appellants either have filed or will file similar motions to dismiss their appeals. District of Columbia - -------------------- In September 1996, the District of Columbia Public Service Commission issued an order designating the issues to be examined regarding electric industry structure and competition. The Company filed comments on the designated issues in early 1997, and on August 31, 1998, the Commission Staff issued its proposal for bringing choice of electric suppliers to District of Columbia customers. The Staff's proposal is currently under the review of the full Commission, which may ultimately reach different conclusions. Pursuant to the Staff's recommendation, competition would be phased in over a two-year period beginning January 1, 2001. Customers representing one-fifth of the electric load in a particular customer class would be able to choose their electric generation supplier at that time. On January 1, 2002, the eligible group increases to one-half of any one customer class, and all customers will then become eligible one year later. The Staff proposed the establishment of working groups to address issues such as conservation, environmental compliance, consumer protection, provision of universal service, supplier certification, and the need for legislation to pave the way for choice. More difficult issues such as the design of unbundled rates and stranded cost estimation and recovery would be addressed in future adjudicatory proceedings. An order was issued by the full Commission on December 30, 1998, in response to the Staff report. The order requires that the Company file a stranded cost study and unbundled rates for the District of Columbia by February 1, 1999. SMECO Agreement - --------------- The Company has had a rolling 10-year full service power supply requirements contract with the SMECO, the Company's principal wholesale customer with a peak load of approximately 600 megawatts. The wholesale portion currently represents approximately 10% of the Company's total kilowatt-hour sales. 76 The contract, by its terms, is extended for an additional year on January 1 of each year, unless notice is given by either party of termination of the contract at the end of the 10-year period. The contract allows SMECO to reduce, by up to 20% each the percentage of its annual requirements that it is obligated to purchase under the contract with a five-year advance notice for each such reduction. On December 31, 1998, the Company and SMECO entered into a new full-requirements agreement that supersedes their existing rolling-10-year power supply contract. The agreement will continue the current total rate for electricity but with a non- varying fuel component and will become effective as of January 1, 1999, if accepted by FERC without change or modification. The agreement will expire on December 31, 2001, following which, SMECO will make a one-time termination payment to the Company of $19 million which compensates the Company for future earnings it would otherwise have received under the 10-year contract. SMECO may elect by January 15, 2000, however, to advance the termination date to December 31, 2000, in which case the termination payment would be $26 million. The Company filed the agreement with FERC for acceptance on December 31, 1998, and expects a decision during the first quarter of 1999. In light of the information contained in the following paragraph, it currently is anticipated that SMECO will elect a December 31, 2000 termination date. The Company will record the applicable termination payment as income upon acceptance of the agreement by FERC. After the termination date, capacity previously used to supply SMECO would be used to serve the Company's retail customers. To the extent the Company makes sales of such capacity in the competitive marketplace, such sales would be used to offset costs otherwise charged to retail customers. Accordingly, applicable costs are expected to be fully recovered in rates charged to retail customers under historical rate making principles. On January 25, 1999, a wholly owned unregulated subsidiary of PCI, signed a contract with SMECO to supply SMECO's full requirements for power (approximately 600 MW of peak load) during the four year period starting January 1, 2001. This contract is subject to acceptance by FERC of the agreement outlined in the preceding paragraph. The subsidiary was the winning bidder in response to SMECO's Summer 1998 call for proposals for a full requirements provider of electricity. A firm commitment has been secured from a third party for the delivery of power sufficient to serve SMECO's full requirements. Both the sales commitment to SMECO and the third party purchase agreement are at fixed prices which do not vary with future changes in market conditions. The subsidiary sells electricity and natural gas and also provides energy services to commercial and industrial customers primarily in the mid-Atlantic region. The new SMECO contract represents the first wholesale electric power contract the subsidiary has secured. 77 Leases - ------ The Company leases its general office building and certain data processing and duplicating equipment, motor vehicles, communication system and construction equipment under long-term lease agreements. The lease of the general office building expires in 2002 and leases of equipment extend for periods of up to 6 years. Charges under such leases are accounted for as operating expenses or construction expenditures, as appropriate. Rents, including property taxes and insurance, net of rental income from subleases, aggregated approximately $18.4 million in 1998, $17.1 million in 1997 and $16.2 million in 1996. The approximate annual commitments under all operating leases, reduced by rentals to be received under subleases are $10.8 million in 1999, $7.9 million in 2000, $5.1 million in 2001, $1.6 million in 2002, $.6 million in 2003 and a total of $4.8 million in the years thereafter. The Company leases its consolidated control center, an integrated energy management system used by the Company's power dispatchers to centrally control the operation of the Company's generating units, transmission system and distribution system. The lease is accounted for as a capital lease, and was recorded at the present value of future lease payments which totaled $152 million. The lease requires semi-annual payments of $7.6 million over a 25-year period and provides for transfer of ownership of the system to the Company for $1 at the end of the lease term. Under SFAS No. 71, the amortization of leased assets is modified so that the total of interest on the obligation and amortization of the leased asset is equal to the rental expense allowed for ratemaking purposes. This lease has been treated as an operating lease for ratemaking purposes. Accordingly, electric plant in service includes a regulatory asset of approximately $28 million and $21 million at December 31, 1998 and 1997, respectively. Fuel Contracts - -------------- The Company has numerous coal contracts for aggregate annual deliveries of approximately three million tons, all of which expire by May 31, 1999. Deliveries under these contracts and the replacement contracts are expected to provide approximately 75% of the estimated system coal requirements in 1999. The Company will purchase the balance of its coal requirements on a spot basis from a variety of suppliers. Prices under the Company's current coal contracts are generally determined by reference to base amounts adjusted to reflect provisions for changes in suppliers' costs, which in turn are determined by reference to published indices and limited by current market prices. 78 Capacity Purchase Agreements - ---------------------------- The Company's long-term capacity purchase agreements with FirstEnergy Corp. (FirstEnergy, formerly Ohio Edison), and Allegheny Energy, Inc. (AEI) commenced June 1, 1987, and are expected to continue at the 450 megawatt level through 2005. Under the terms of the agreements with FirstEnergy and AEI, the Company is required to make capacity payments, subject to certain contingencies, which include a share of FirstEnergy's fixed operating and maintenance cost. The Company also has a 25-year agreement with Panda-Brandywine, L.P. (Panda) for a 230- megawatt gas-fueled combined-cycle cogenerator project in Prince George's County, Maryland. In addition, the Company continues to purchase capacity and associated energy from a municipally financed resource recovery facility in Montgomery County, Maryland. The capacity expense under these agreements, including an allocation of a portion of FirstEnergy's fixed operating and maintenance costs, was $149.8 million, $145.2 million and $120 million in 1998, 1997 and 1996, respectively. Commitments under these agreements, are estimated at $203 million in 1999, $204 million in 2000, $209 million in 2001, $210 million in 2002 and 2003, and $1.2 billion in the years thereafter. The Company began a 25-year purchase agreement in June 1990 with SMECO for 84 megawatts of capacity supplied by a combustion turbine installed and owned by SMECO at the Company's Chalk Point Generating Station. The Company is responsible for all costs associated with operating and maintaining the facility. The Company is accounting for this agreement as a capital lease, recorded at fair market value which totaled $37.1 million at the date construction was completed. The capacity payment to SMECO is approximately $5.5 million per year. Under SFAS No. 71, amortization of leased assets is modified so that the total of interest on the obligation and amortization of the leased asset is equal to rental expense allowed for ratemaking purposes. This agreement has been treated as an operating lease for ratemaking purposes. Accordingly, electric plant in service includes a regulatory asset of approximately $9 million and $8 million at December 31, 1998 and 1997, respectively. Environmental Contingencies - --------------------------- The Company is subject to contingencies associated with environmental matters, principally related to possible obligations to remove or mitigate the effects on the environment of the disposal of certain substances at the sites discussed below. On May 22, 1998, the State of Maryland issued final regulations entitled "Post RACT Requirements for Nitrogen Oxides (NOx) Sources (NOx Budget Proposal)," requiring a 65% reduction 79 in NOx emissions at the Company's Maryland generating units by May 1, 1999. The regulations allow the purchase or trade of NOx emission allowances to fulfill this obligation. The Company appealed this regulation to the Circuit Court for Charles County, Maryland on June 19, 1998, on the basis that the regulation does not provide adequate time for the installation of NOx emission reduction technology and that there is no functioning NOx allowance market. On July 17, 1998, the case was moved to the Circuit Court for Baltimore City and consolidated with a similar appeal filed by Baltimore Gas and Electric Company. The Company believes it is unlikely that a market containing NOx allowances sufficient to ensure compliance will be functioning by May 1999; presently, eight states have enacted the rules necessary to create such a market. A preliminary plan for installing the best available removal technology on the Company's largest coal-fired units would require capital expenditures of approximately $170 million and would yield NOx reductions of nearly 85% beginning in year 2004. The Company cannot predict the outcome of this litigation and is evaluating its options in the event of an adverse decision. Also, on September 24, 1998, the EPA issued rules for reducing interstate transport of ozone. The Company's preliminary plan for NOx reductions of 85% by 2004 appears to be consistent with the EPA rules. The Company's generating stations operate under National Pollutant Discharge Eliminating System (NPDES) permits. A NPDES renewal application submitted in July 1993 for the Benning station is pending. NPDES permits were issued for the Potomac River station in February 1994, the Morgantown station in February 1995, the Dickerson station in August 1996 and the Chalk Point station in September 1996. An NPDES renewal application was submitted for the Potomac River station in August 1998. In October 1997, the Company received notice from the EPA that it, along with 68 other parties, may be a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA or Superfund) at the Butler Mine Tunnel Superfund site in Pittstown Township, Luzerne County, Pennsylvania. The site is a mine drainage tunnel with an outfall on the Susquehanna River where oil waste was disposed via a borehole in the tunnel. The letter notifying the Company of its potential liability also contained a request for a reimbursement of approximately $.8 million for response costs incurred by EPA at the site. The letter requested that the Company submit a good faith proposal to conduct or finance the remedial action contained in a July 1996 Record of Decision (ROD). The EPA estimates the present cost of the remedial action to be $3.7 million. While the Company cannot predict its liability at this site, the Company believes that it will not have a material adverse effect on its financial position or results of operations. 80 In December 1995, the Company received notice from the EPA that it is a PRP with respect to the release or threatened release of radioactive and mixed radioactive and hazardous wastes at a site in Denver, Colorado, operated by RAMP Industries, Inc. Evidence indicates that the Company's connection to the site arises from an agreement with a vendor to package, transport and dispose of two laboratory instruments containing small amounts of radioactive material at a Nevada facility. While the Company cannot predict its liability at this site, the Company believes that it will not have a material adverse effect on its financial position or results of operations. In October 1995, the Company received notice from the EPA that it, along with several hundred other companies, may be a PRP in connection with the Spectron Superfund Site located in Elkton, Maryland. The site was operated as a hazardous waste disposal, recycling, and processing facility from 1961 to 1988. A group of PRPs allege, based on records they have collected, that the Company's share of liability at this site is .0042%. The EPA has also indicated that a de minimis settlement is likely to be appropriate for this site. While the outcome of negotiations and the ultimate liability with respect to this site cannot be predicted, the Company believes that its liability at this site will not have a material adverse effect on its financial position or results of operations. In December 1987, the Company was notified by the EPA that it, along with several other utilities and nonutilities, is a PRP in connection with the polychlorinated biphenyl compounds (PCBs) contamination of a Philadelphia, Pennsylvania site owned by a nonaffiliated company. In the early 1970's, the Company sold scrap transformers, some of which may have contained some level of PCBs, to a metal reclaimer operating at the site. In October 1994, a Remedial Investigation/Feasibility Study (RI/FS) including a number of possible remedies was submitted to the EPA. In December 1997, the EPA signed a ROD that set forth a selected remedial action plan with estimated implementation costs of approximately $17 million. On June 26, 1998, the EPA issued a unilateral Administrative Order to the Company and 12 other PRPs to conduct the design and actions called for in the ROD. To date, the Company has accrued $1.7 million for its share of these costs. Litigation - ---------- During 1993, the Company was served with Amended Complaints filed in three jurisdictions (Prince George's County, Baltimore City, and Baltimore County), in separate ongoing, consolidated proceedings each denominated "In re: Personal Injury Asbestos Case". The Company (and other defendants) were brought into these cases on a theory of premises liability under which plaintiffs argue that the Company was negligent in not providing 81 a safe work environment for employees of its contractors who allegedly were exposed to asbestos while working on the Company's property. Initially, a total of approximately 448 individual plaintiffs added the Company to their Complaints. While the pleadings are not entirely clear, it appears that each plaintiff seeks $2 million in compensatory damages and $4 million in punitive damages from each defendant. In a related proceeding in the Baltimore City case, the Company was served, in September 1993, with a third party complaint by Owens Corning Fiberglass, Inc. (Owens Corning) alleging that Owens Corning was in the process of settling approximately 700 individual asbestos-related cases and seeking a judgment for contribution against the Company on the same theory of alleged negligence set forth above in the plaintiffs' case. Subsequently, Pittsburgh Corning Corp. (Pittsburgh Corning) filed a third party complaint against the Company, seeking contribution for the same plaintiffs involved in the Owens Corning third party complaint. Since the initial filings in 1993, approximately 65 additional individual suits have been filed against the Company. The third party complaints involving Pittsburgh Corning and Owens Corning were dismissed by the Baltimore City Court during 1994 without any payment by the Company. Through December 31, 1998, approximately 400 of the individual plaintiffs have dismissed their claims against the Company. No payments were made by the Company in connection with the dismissals. While the aggregate amount specified in the remaining suits would exceed $400 million, the Company believes the amounts are greatly exaggerated as were the claims already disposed of. The amount of total liability, if any, and any related insurance recovery cannot be precisely determined at this time; however, based on information and relevant circumstances known at this time, the Company does not believe these suits will have a material adverse effect on its financial position. However, an unfavorable decision rendered against the Company could have a material adverse effect on results of operations in the year in which a decision is rendered. The Company is involved in other legal and administrative (including environmental) proceedings before various courts and agencies with respect to matters arising in the ordinary course of business. Management is of the opinion that the final disposition of these proceedings will not have a material adverse effect on the Company's financial position or results of operations. Labor Agreement - --------------- A new four-year Agreement between the Company and Local 1900 of the International Brotherhood of Electrical Workers (IBEW) was ratified on December 18, 1998, by Union members. The Agreement provides for a general wage increase of 3% each year in 1999, 2000 and 2001, beginning February 14, 1999 and a 3% increase in wages in the fourth year of the contract (2002) unless either 82 party elects to reopen the Agreement. The Company also agreed to a 3% lump-sum payment for the period of January 3, 1999, to February 14, 1999. In addition, the Agreement resolves important issues that would arise in the event of a divestiture of the Company's generating assets and establishes a framework for ongoing progress towards improving management and union relations with joint committees. At December 31, 1998, 2,286 of the Company's 3,716 employees were represented by the IBEW. Termination of Proposed Merger - ------------------------------ In December 1997, the Company and Baltimore Gas and Electric Company announced the cancellation of their proposed merger (the Merger) to create Constellation Energy Corporation. As a result, the Company recorded a $52.5 million non-operating charge ($32.6 million net of income tax or 28 cents per share) to write off its cumulative deferred Merger-related costs. 83 (14) Selected Nonutility Subsidiary Financial Information ---------------------------------------------------- Selected financial information of PCI is presented below. Subsidiary equity at December 31, 1998, and December 31, 1997, was $243.4 million and $227 million, respectively. These amounts include $7.8 million and $6.5 million of unrealized appreciation, at December 31, 1998 and 1997, respectively, relating to the marketable securities portfolio on an after-tax basis. - ----------------------------------------------------------------- For the year ended December 31, 1998 1997 1996 - ----------------------------------------------------------------- (Millions of Dollars) Income Leasing activities $ 73.3 $ 75.6 $ 91.7 Marketable securities 19.3 28.6 33.7 Energy services 28.0 6.3 - Utility related services 14.5 16.2 7.7 Other 8.4 (1.6) (11.5) ------- ------- ------- 143.5 125.1 121.6 ------- ------- ------- Expenses Interest 56.2 69.0 83.4 Operating and other 57.4 35.2 34.6 Depreciation 23.5 35.6 41.3 Income tax credit (8.7) (31.8) (54.6) ------- ------- ------- 128.4 108.0 104.7 ------- ------- ------- Net earnings from nonutility subsidiary $ 15.1 $ 17.1 $ 16.9 ======= ======= ======= 84 Marketable Securities - --------------------- PCI's marketable securities, primarily preferred stocks with mandatory redemption features, are classified as available-for- sale for financial reporting purposes. Net unrealized gains or losses on such securities are reflected, net of tax, in stockholder's equity. The net unrealized gains on marketable securities, which relate primarily to mandatory redeemable preferred stock, are shown below: - ----------------------------------------------------------------- December 31, 1998 1997 1996 - ----------------------------------------------------------------- (Millions of Dollars) Market Value $ 231.1 $ 302.5 $ 377.2 Cost 219.1 292.6 375.6 ------- ------- ------- Net unrealized gain $ 12.0 $ 9.9 $ 1.6 ======= ======= ======= - ----------------------------------------------------------------- Included in net unrealized gains and losses are gross unrealized gains of $12.4 million and gross unrealized losses of $.4 million at December 31, 1998, gross unrealized gains of $13.9 million and gross unrealized losses of $4 million at December 31, 1997, and gross unrealized gains of $9.9 million and gross unrealized losses of $8.3 million at December 31, 1996. In determining gross realized gains and losses on sales or maturities of securities, specific identification is used. Gross realized gains were $4.7 million, $7.5 million and $4.7 million in 1998, 1997 and 1996, respectively. Gross realized losses were $2.5 million, $.6 million and $1.1 million in 1998, 1997 and 1996, respectively. At December 31, 1998, the contractual maturities for mandatorily redeemable preferred stock are $12.9 million within one year, $91.8 million from one to five years, $76.2 million from five to 10 years and $37.3 million for over 10 years. 85 Leasing Activities - ------------------ PCI's net investment in finance leases is summarized below. - ----------------------------------------------------------------- December 31, 1998 1997 - ----------------------------------------------------------------- (Millions of Dollars) Rents receivable $ 555.1 $ 664.2 Estimated residual values 69.7 88.0 Less: Unearned and deferred income (225.6) (288.6) ------- ------- Investment in finance leases 399.2 463.6 Less: Deferred taxes arising from finance leases (134.3) (119.5) ------- ------- Net investment in finance leases $ 264.9 $ 344.1 ======= ======= - ----------------------------------------------------------------- Minimum lease payments receivable from finance leases, primarily aircraft, for each of the years 1999 through 2003 are $26.7 million, $29.5 million, $29 million, $19.3 million, and $19.4 million, respectively. Net income from leveraged leases was $14.7 million in 1998, $16.4 million in 1997 and $22.5 million in 1996. Rent payments receivable from aircraft operating leases for each of the years 1999 through 2003 are $31.2 million in 1999, $27.7 million in 2000, $21.5 million in 2001, $2.6 million in 2002 and zero in 2003. 86 (15) Segment Information The Company has identified the utility and nonutility business operations as its two segments. The factors used to identify these segments are that the Company organizes its business around differences in products, services, and regulatory environments and that the operating results for each segment are regularly reviewed by the Company's chief operating decision maker in order to make decisions about resources and assess performance. Revenues for the utility segment are derived from the generation, transmission, distribution and sale of electric energy. The nonutility segment, which primarily consists of the operations of the Company's wholly owned subsidiary, PCI, derives its revenue from investment programs, energy-related businesses and telecommunication services. The following table presents information about the Company's reportable segments for the year ended December 31, 1998, 1997 and 1996: 87 General Segment Information - --------------------------- (Millions of Dollars)
Segment 1998 Utility Nonutility Totals ---- ---------- ---------- ---------- Revenues $ 2,063.9 $ 143.5 $ 2,207.4 ---------- ---------- ---------- Operating expenses and other 1,334.8 57.4 1,392.2 Depreciation and amortization 239.8 23.5 263.3 Income tax expense (credit) 130.5 (8.7) 121.8 ---------- ---------- ---------- Operating Income 358.8 71.3 430.1 Interest Expense 147.6 56.2 203.8 ---------- ---------- ---------- Net Income $ 211.2 $ 15.1 $ 226.3 ========== ========== ========== Total Assets $ 5,843.2 $ 1,086.4 $ 6,929.6 Expenditures for Assets $ 206.2 $ - $ 206.2 Segment 1997 Utility Nonutility Totals ---- ---------- ---------- ---------- Revenues $ 1,863.5 $ 125.1 $ 1,988.6 ---------- ---------- ---------- Operating expenses and other 1,210.2 35.2 1,245.4 Depreciation and amortization 232.0 35.6 267.6 Income tax expense (credit) 117.7 (31.8) 85.9 ---------- ---------- ---------- Operating Income 303.6 86.1 389.7 Interest Expense 138.9 69.0 207.9 ---------- ---------- ---------- Net Income $ 164.7 $ 17.1 $ 181.8 ========== ========== ========== Total Assets $ 5,779.3 $ 1,167.3 $ 6,946.6 Expenditures for Assets $ 217.2 $ - $ 217.2 Segment 1996 Utility Nonutility Totals ---- ---------- ---------- ---------- Revenues $ 2,010.3 $ 121.6 $ 2,131.9 ---------- ---------- ---------- Operating expenses and other 1,293.7 34.6 1,328.3 Depreciation and amortization 223.0 41.3 264.3 Income tax expense (credit) 134.1 (54.6) 79.5 ---------- ---------- ---------- Operating Income 359.5 100.3 459.8 Interest Expense 139.4 83.4 222.8 ---------- ---------- ---------- Net Income $ 220.1 $ 16.9 $ 237.0 ========== ========== ========== Total Assets $ 5,724.8 $ 1,363.8 $ 7,088.6 Expenditures for Assets $ 179.9 $ - $ 179.9 The Company's revenues from external customers are earned primarily within the United States and principally all of the Company's long-lived assets are held in the United States. In addition, there were no material transactions between segments. Total segment assets of $6,929.6 million, $6,946.6 million, and $7,088.6 million as of December 31, 1998, 1997 and 1996, respectively, include $243.4 million, $227 million and $196.3 million representing the utility segment's investment in the nonutility subsidiary and $31.4 million, $12 million and $.4 million of intersegment net receivables. As of December 31, 1998, 1997 and 1996, respectively, these amounts are eliminated in consolidation and therefore not reflected in the Company's total assets as recorded on the Consolidated Balance Sheets. 88
(16) Quarterly Financial Summary (Unaudited)
- ------------------------------------------------------------------------------------------------------- 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter Total - ------------------------------------------------------------------------------------------------------- (Millions of Dollars, except Per Share Data) 1998 Operating Revenue $ 369.8 479.4 670.2 366.7 1,886.1 Total Revenue $ 380.4 528.5 750.8 404.2 2,063.9 Operating Expenses $ 344.5 432.8 564.8 367.5 1,709.6 Operating Income $ 35.9 95.7 186.0 36.7 354.3 Net Income (Loss) $ 7.5 66.0 153.1 (.3) 226.3 Earnings (Loss) for Common Stock $ 3.4 56.0 151.1 (2.2) 208.3 Basic Earnings (Loss) per Common Share $ .03 .47 1.27 (.02) 1.76 Diluted Earnings (Loss) per Common Share $ .03 .46 1.23 (.02) 1.73 Dividends per Share $ .415 .415 .415 .415 1.66 1997 Operating Revenue $ 374.5 439.5 618.2 378.6 1,810.8 Total Revenue $ 389.1 451.0 633.0 390.4 1,863.5 Operating Expenses $ 346.8 370.4 466.5 354.4 1,538.1 Operating Income $ 42.3 80.6 166.5 36.0 325.4 Net Income (Loss) $ 23.0 50.1 136.0 (27.3) 181.8 Earnings (Loss) for Common Stock $ 18.9 46.0 131.8 (31.4) 165.3 Basic Earnings (Loss) per Common Share $ .16 .39 1.11 (.27) 1.39 Diluted Earnings (Loss) per Common Share $ .16 .38 1.07 (.27) 1.38 Dividends per Share $ .415 .415 .415 .415 1.66 1996 Operating Revenue $ 385.3 462.7 614.3 372.5 1,834.8 Total Revenue $ 436.6 501.8 658.2 413.7 2,010.3 Operating Expenses $ 392.6 406.5 491.9 370.9 1,661.9 Operating Income $ 44.0 95.3 166.3 42.8 348.4 Net Income $ 14.7 72.3 138.7 11.3 237.0 Earnings for Common Stock $ 10.6 68.1 134.6 7.1 220.4 Basic Earnings per Common Share $ .09 .57 1.14 .06 1.86 Diluted Earnings per Common Share $ .09 .56 1.09 .06 1.82 Dividends per Share $ .415 .415 .415 .415 1.66 The Company's sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful. The totals of the four quarterly basic earnings per common share and diluted earnings per common share may not equal the basic earnings per common share and diluted earnings per common share for the year due to changes in the number of common shares outstanding during the year and, with respect to the diluted earnings per common share, changes in the amount of dilutive securities. 89
Stock Market Information
- ------------------------------------------------------------------------------------------------------------------------------------ 1998 High Low 1997 High Low - ------------------------------------------------------------------------------------------------------------------------------------ 1st Quarter $25-11/16 $23-7/16 1st Quarter $26 $23-7/8 2nd Quarter $25-7/16 $23-1/16 2nd Quarter $24-7/8 $21-1/8 3rd Quarter $26-5/8 $23-1/8 3rd Quarter $23-3/4 $21 4th Quarter $27-13/16 $24-7/8 4th Quarter $26 $21 (Close $26-5/16) (Close $25-13/16) Shareholders at December 31, 1998: 72,607 - ------------------------------------------------------------------------------------------------------------------------------------
Selected Consolidated Financial Data
- ------------------------------------------------------------------------------------------------------------------------------------ 1998 1997 1996 1995 1994 1993 1988 - ------------------------------------------------------------------------------------------------------------------------------------ (Millions, except Per Share Data) Operating Revenue $ 1,886.1 1,810.8 1,834.8 1,822.4 1,790.6 1,702.4 1,349.8 Total Revenue $ 2,063.9 1,863.5 2,010.3 1,876.1 1,823.1 1,725.2 1,411.6 Operating Expenses $ 1,709.6 1,538.1 1,661.9 1,528.4 1,498.6 1,400.5 1,138.6 Net Earnings (Loss) from Nonutility Subsidiary $ 15.1 17.1 16.9 (124.4) 19.1 25.1 27.9 Net Income $ 226.3 181.8 237.0 94.4 227.2 241.6 211.1 Earnings for Common Stock $ 208.3 165.3 220.4 77.5 210.7 225.3 201.8 Basic Common Shares Outstanding (Average) 118.5 118.5 118.5 118.4 118.0 115.6 94.4 Diluted Common Shares Outstanding (Average) 124.2 124.3 124.3 118.5 124.0 121.6 97.3 Basic Earnings (Loss) Per Common Share Utility Operations $ 1.63 1.25 Includes ($.28) as the net effect of the write-off of merger-related costs. 90
EX-27 3
UT 0000079732 POTOMAC ELECTRIC POWER COMPANY 1 POTOMAC CAPITAL INVESTMENT CORPORATION 1,000 12-MOS DEC-31-1998 JAN-01-1998 DEC-31-1998 PER-BOOK 4,481,200 0 391,700 655,500 1,126,400 6,654,800 118,500 1,011,600 747,300 1,877,400 50,000 100,000 1,859,000 0 0 191,700 45,200 0 157,600 20,800 2,353,100 6,654,800 2,063,900 130,500 1,579,100 1,709,600 354,300 19,600 373,900 147,600 226,300 18,000 208,300 196,600 139,000 417,200 1.76 $1.73 Included on the Balance Sheet in the caption "short-term debt." Includes redeemable preferred securities of subsidiary trust. Includes preferred stock redemption premium of $6,600. Total annualized interest cost for all utility long-term debt and manditorily redeemable preferred securities of subsidiary trust outstanding at December 31, 1998. Basic earnings per share for the twelve months ended December 31, 1998 were $1.76. Diluted earnings per share for the twelve months ended December 31, 1998 were $1.73.
EX-23 4 Item 7 Exhibit 23 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Prospectuses constituting parts of the Registration Statements on Form S-8 (Numbers 33- 36798, 33-53685 and 33-54197) and on Form S-3 (Numbers 33-58810, 33-61379, 333-33495 and 333-66127) of Potomac Electric Power Company of our report dated January 25, 1999 appearing on page 38 of Exhibit 99 of the Current Report on Form 8-K of Potomac Electric Power Company dated January 29, 1999. /s/ PRICEWATERHOUSECOOPERS LLP PricewaterhouseCoopers LLP Washington, D.C. January 29, 1999 EX-12 5 Item 7 Exhibit 12 Computation of Ratios --------------- ---------------------------------- The computations of the coverage of fixed charges, before income taxes, and the coverage of combined fixed charges and preferred dividends for each of the years 1998 through 1994 on the basis of parent company operations only, are as follows.
For The Year Ended December ------------------------------------------------------- 1998 1997 1996 1995 1994 ------------------------------------------------------- (Millions of Dollars) Net income $211.2 $164.7 $220.1 $218.8 $208.1 Taxes based on income 131.0 97.5 135.0 129.4 116.6 ------------------------------------------------------- Income before taxes 342.2 262.2 355.1 348.2 324.7 ------------------------------------------------------- Fixed charges: Interest charges 151.8 146.7 146.9 146.6 139.2 Interest factor in rentals 23.8 23.6 23.6 23.4 6.3 ------------------------------------------------------- Total fixed charges 175.6 170.3 170.5 170.0 145.5 ------------------------------------------------------- Income before income taxes and fixed charges $517.8 $432.5 $525.6 $518.2 $470.2 ====== ====== ====== ====== ====== Coverage of fixed charges 2.95 2.54 3.08 3.05 3.23 ==== ==== ==== ==== ==== Preferred dividend requirements $18.0 $16.5 $16.6 $16.9 $16.5 ------------------------------------------------------- Ratio of pre-tax income to net income 1.62 1.59 1.61 1.59 1.56 ------------------------------------------------------- Preferred dividend factor $29.2 $26.2 $26.7 $26.9 $25.7 ------------------------------------------------------- Total fixed charges and preferred dividends $204.8 $196.5 $197.2 $196.9 $171.2 ====== ====== ====== ====== ====== Coverage of combined fixed charges and preferred dividends 2.53 2.20 2.66 2.63 2.75 ==== ==== ==== ==== ====
Item 7 Exhibit 12 Computation of Ratios --------------- ---------------------------------- The computations of the coverage of fixed charges, before income taxes, and the coverage of combined fixed charges and preferred dividends for each of the years 1998 through 1994 on a fully consolidated basis are as follows.
For The Year Ended December ------------------------------------------------------- 1998 1997 1996 1995 1994 ------------------------------------------------------- (Millions of Dollars) Net income $226.3 $181.8 $237.0 $94.4 $227.2 Taxes based on income 122.3 65.6 80.4 43.7 94.0 ------------------------------------------------------- Income before taxes 348.6 247.4 317.4 138.1 321.2 ------------------------------------------------------- Fixed charges: Interest charges 208.6 216.1 231.1 238.7 224.5 Interest factor in rentals 24.0 23.7 23.9 26.7 9.9 ------------------------------------------------------- Total fixed charges 232.6 239.8 255.0 265.4 234.4 ------------------------------------------------------- Nonutility subsidiary capitalized interest (0.6) (0.5) (0.7) (0.5) (0.5) ------------------------------------------------------- Income before income taxes and fixed charges $580.6 $486.7 $571.7 $403.0 $555.1 ====== ====== ====== ====== ====== Coverage of fixed charges 2.50 2.03 2.24 1.52 2.37 ==== ==== ==== ==== ==== Preferred dividend requirements $18.0 $16.5 $16.6 $16.9 $16.5 ------------------------------------------------------- Ratio of pre-tax income to net income 1.54 1.36 1.34 1.46 1.41 ------------------------------------------------------- Preferred dividend factor $27.7 $22.4 $22.2 $24.7 $23.3 ------------------------------------------------------- Total fixed charges and preferred dividends $260.3 $262.2 $277.2 $290.1 $257.7 ====== ====== ====== ====== ====== Coverage of combined fixed charges and preferred dividends 2.23 1.86 2.06 1.39 2.15 ==== ==== ==== ==== ====
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