-----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, Wp2DSFDYXwkOCcNWT+kAA2mXSjMafORyY0Fe2ZTzGPtYOVPt/v/rw9nGf1iuSkFg 4m3CvvUeBT5cK9us0B8Kjg== 0000079732-98-000010.txt : 19980128 0000079732-98-000010.hdr.sgml : 19980128 ACCESSION NUMBER: 0000079732-98-000010 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19980126 ITEM INFORMATION: FILED AS OF DATE: 19980126 SROS: NYSE 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: 98512957 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: 2028722456 8-K 1 CURRENT REPORT 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 26, 1998 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) 872-3526 _______________________________________________________________________ (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 1997 consolidated financial statements of the Company and Subsidiary, together with the report thereon of Price Waterhouse dated January 16, 1998; and Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition as well as selected financial data......................Filed herewith. -2- 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) /S/ D. R. WRAASE By ___________________________ Dennis R. Wraase Senior Vice President and Chief Financial Officer January 26, 1998 DATE -3- EX-12 2 COMPUTATION OF RATIOS 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 1997 through 1993 on the basis of parent company operations only, are as follows.
For The Year Ended December 31, ------------------------------------------------------- 1997 1996 1995 1994 1993 ------------------------------------------------------- (Thousands of Dollars) Net income $164,749 $220,066 $218,788 $208,074 $216,478 Taxes based on income 97,487 135,011 129,439 116,648 107,223 ------------------------------------------------------- Income before taxes 262,236 355,077 348,227 324,722 323,701 ------------------------------------------------------- Fixed charges: Interest charges 146,703 146,939 146,558 139,210 141,393 Interest factor in rentals 23,616 23,560 23,431 6,300 5,859 ------------------------------------------------------- Total fixed charges 170,319 170,499 169,989 145,510 147,252 ------------------------------------------------------- Income before income taxes and fixed charges $432,555 $525,576 $518,216 $470,232 $470,953 ======== ======== ======== ======== ======== Coverage of fixed charges 2.54 3.08 3.05 3.23 3.20 ==== ==== ==== ==== ==== Preferred dividend requirements $16,579 $16,604 $16,851 $16,437 $16,255 ------------------------------------------------------- Ratio of pre-tax income to net income 1.59 1.61 1.59 1.56 1.50 ------------------------------------------------------- Preferred dividend factor $26,361 $26,732 $26,793 $25,642 $24,383 ------------------------------------------------------- Total fixed charges and preferred dividends $196,680 $197,231 $196,782 $171,152 $171,635 ======== ======== ======== ======== ======== Coverage of combined fixed charges and preferred dividends 2.20 2.66 2.63 2.75 2.74 ==== ==== ==== ==== ====
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 1997 through 1993 on a fully consolidated basis are as follows.
For The Year Ended December 31, ------------------------------------------------------- 1997 1996 1995 1994 1993 ------------------------------------------------------- (Thousands of Dollars) Net income $181,830 $236,960 $94,391 $227,162 $241,579 Taxes based on income 65,669 80,386 43,731 93,953 62,145 ------------------------------------------------------- Income before taxes 247,499 317,346 138,122 321,115 303,724 ------------------------------------------------------- Fixed charges: Interest charges 216,156 231,029 238,724 224,514 221,312 Interest factor in rentals 23,687 23,943 26,685 9,938 9,257 ------------------------------------------------------- Total fixed charges 239,843 254,972 265,409 234,452 230,569 ------------------------------------------------------- Nonutility subsidiary capitalized interest (493) (649) (529) (521) (2,059) ------------------------------------------------------- Income before income taxes and fixed charges $486,849 $571,669 $403,002 $555,046 $532,234 ======== ======== ======== ======== ======== Coverage of fixed charges 2.03 2.24 1.52 2.37 2.31 ==== ==== ==== ==== ==== Preferred dividend requirements $16,579 $16,604 $16,851 $16,437 $16,255 ------------------------------------------------------- Ratio of pre-tax income to net income 1.36 1.34 1.46 1.41 1.26 ------------------------------------------------------- Preferred dividend factor $22,547 $22,249 $24,602 $23,176 $20,481 ------------------------------------------------------- Total fixed charges and preferred dividends $262,390 $277,221 $290,011 $257,628 $251,050 ======== ======== ======== ======== ======== Coverage of combined fixed charges and preferred dividends 1.86 2.06 1.39 2.15 2.12 ==== ==== ==== ==== ====
EX-23 3 CONSENT OF INDEPENDENT ACCOUNTANTS 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 and 333-33495) of Potomac Electric Power Company of our report dated January 16, 1998 appearing on page 29 of Exhibit 99 of the Current Report on Form 8-K of Potomac Electric Power Company dated January 26, 1998. /s/ PRICE WATERHOUSE LLP Price Waterhouse LLP Washington, D.C. January 26, 1998 EX-27 4 FINANCIAL DATA SCHEDULE
UT 1 POTOMAC CAPITAL INVESTMENT CORPORATION 1,000 12-MOS DEC-31-1997 JAN-01-1997 DEC-31-1997 PER-BOOK 4,464,272 0 392,600 661,298 1,189,387 6,707,557 118,501 1,010,209 734,318 1,863,028 141,000 125,290 1,901,486 0 0 131,375 51,069 985 160,406 20,772 2,312,146 6,707,557 1,863,510 117,731 1,420,396 1,538,127 325,383 (4,723) 320,660 138,830 181,830 16,579 165,251 196,615 132,600 434,819 $1.39 $1.38 Included on the Balance Sheet in the caption "Short-term debt." Total annualized interest costs for all utility long-term debt outstanding at December 31, 1997. Effective December 31, 1997, the Company adopted Statement of Financial Accounting Standards No. 128 entitled "Earnings per Share." Accordingly, the Company's Earnings per Share are as follows: Basic $1.39; Diluted $1.38.
EX-99 5 FINANCIAL STATEMENTS POTOMAC ELECTRIC POWER COMPANY ------------------------------ AND --- SUBSIDIARY ---------- Consolidated Financial Statements --------------------------------- For the Year Ended December 31, 1997 ------------------------------------ Item 7 Exhibit 99 Financial Information - --------------------- Potomac Electric Power Company and Subsidiary Contents - -------- Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition...................................... 2 Report of Independent Accountants.......................... 29 Consolidated Statements of Earnings........................ 30 Consolidated Balance Sheets................................ 31 Consolidated Statements of Cash Flows...................... 33 Notes to Consolidated Financial Statements................. 34 Selected Consolidated Financial Data....................... 70 1 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition - ---------------------------------------------------- TERMINATION OF PROPOSED MERGER - ------------------------------ On December 22, 1997, Potomac Electric Power Company (the Company, PEPCO) 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. At December 31, 1996, deferred costs related to the Merger totaled $29 million and are included in "Other Deferred Charges" on the Consolidated Balance Sheet. While all necessary regulatory approvals had been received, the orders of both the Maryland and the District of Columbia public service commissions contained financial conditions that made it impossible for the two companies' investors to share in the benefits of the proposed Merger. The regulatory plan proposed by the companies had called for an equal sharing of the savings between customers and shareholders. Both commission orders returned more than the estimated total Merger savings to the customers. The companies tried unsuccessfully to obtain timely reconsideration of these conditions but concluded that a favorable outcome could not be expected within a reasonable period, if at all. 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 47% of the Company's total revenue in 1997. Fuel and purchased energy, capacity purchase payments and other operating expenses were 53% of total revenue. The Company's wholly owned subsidiary, Potomac Capital Investment Corporation (PCI), conducts nonutility investment programs and businesses with the objective of supplementing current utility earnings and building long-term shareholder value. 2 The information set forth below discusses the results of operations, capital resources and liquidity during the period 1995 through 1997 for the Company and PCI. The Company's earnings for common stock during 1997 totaled $165.3 million, as compared to $220.4 million in 1996. As set forth below, utility earnings per share from operations decreased from $1.72 in 1996 to $1.53 in 1997, excluding the December 1997 write-off of Merger related costs of 28 cents per share. Consolidated earnings decreased from $1.86 to $1.39 in 1997. The 1995 nonutility subsidiary results reflect noncash, nonrecurring charges of $1.04 related to PCI's May 1995 plan with respect to the aircraft equipment leasing business. - ----------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------- Utility Operations $1.53 $1.72 $1.70 Merger Costs (.28) - - Nonutility Subsidiary .14 .14 (1.05) ----- ----- ----- Consolidated $1.39 $1.86 $ .65 ===== ===== ===== - ----------------------------------------------------------------- The average number of common shares outstanding at December 31, 1997, was relatively unchanged from December 31, 1996. 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. 3 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 (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 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 District of Columbia and Maryland public service commissions, future economic conditions and the influence exerted by emerging market forces over the structure of the electric industry. 4 UTILITY - ------- RESULTS OF OPERATIONS - --------------------- Total Revenue - ------------- The changes in total revenue are shown in the following table. - ----------------------------------------------------------------- Increase (Decrease) from Prior Year 1997 1996 1995 - ----------------------------------------------------------------- (Millions of Dollars) Change in kilowatt-hour sales $ (8.6) $(11.5) $ 27.2 Change in base rate revenue (7.2) 27.0 42.8 Change in fuel adjustment clause billings to cover cost of fuel and interchange and capacity purchase payments (9.2) (4.5) (39.3) Change in other revenue 1.0 1.4 1.1 ------- ------ ------ Change in Operating Revenue (24.0) 12.4 31.8 ------- ------ ------ Change in interchange deliveries (122.8) 121.8 21.2 ------- ------ ------ Change in Total Revenue $(146.8) $134.2 $ 53.0 ======= ====== ====== - ----------------------------------------------------------------- The decrease in 1997 base rate revenue compared to 1996 primarily reflects a decrease of $7.3 million in the conservation incentive provision of the Company's Demand Side Management (DSM) surcharge in Maryland. The conservation incentive, totaling $1.6 million, was awarded for achieving specified 1996 Maryland energy goals. The Company recorded an $8.9 million bonus in 1996 for achieving specified 1995 energy goals. The increase in base rate revenue in 1996 as compared to 1995 reflects the continued effects of a District of Columbia rate increase of $27.9 million (effective July 1995) and an increase of $17.7 million associated with the Company's DSM surcharge in Maryland, which includes a $.2 million increase in the conservation incentive provision of the tariff for achieving specified 1995 Maryland energy goals. 5 The increase in base rate revenue in 1995 as compared to 1994 reflects the effect of a District of Columbia rate increase of $27.9 million (effective July 1995) and the continued effect of a 1994 rate increase in the District of Columbia. In addition, 1995 base rate revenue reflects an increase of $28 million associated with the Company's DSM surcharge in Maryland, which includes a $3.7 million increase in the conservation incentive provision of the tariff for achieving specified 1994 Maryland energy goals. The decrease in 1997 in revenue from interchange deliveries reflects the change in the level of activity in purchase-for- resale agreements under the Company's wholesale power sales tariff, predominantly where the Company buys energy from one party for the purpose of selling that energy to a third party. Beginning in January 1997 through March 1997, and pursuant to FERC's Order No. 888, the Company implemented an open access transmission tariff (OATT) and terminated the purchase-for-resale agreements. On April 1, 1997, the Pennsylvania-New Jersey- Maryland Interconnection Association (PJM) implemented an OATT on behalf of its transmission owners, replacing the Company's OATT. The Company classifies revenue from service agreements under these tariffs as "Other operating revenue". In addition, interchange deliveries include revenue from bilateral energy transactions and the sale of short-term generating capacity. The increases in 1996 and 1995 in revenue from interchange deliveries reflect the growth in the number of companies involved in power sales tariff interchange transactions, and changes in levels and pricing of energy delivered to PJM. The benefits derived from interchange deliveries, the allocated amounts of capacity sales in the District of Columbia (approximately 40%) and revenue under the OATT are passed through to the Company's customers through a fuel adjustment clause. 6 Kilowatt-hour Sales - ------------------- - ----------------------------------------------------------------- 1997 1996 vs. vs. 1997 1996 1995 1996 1995 - ----------------------------------------------------------------- (Millions of Kilowatt-hours) By Customer Type Residential 6,552 6,869 6,707 (4.6)% 2.4% Commercial 11,811 11,712 11,861 .8 (1.3) U.S. Government 3,934 3,902 3,998 .8 (2.4) D.C. Government 850 847 879 .4 (3.6) Wholesale 2,561 2,570 2,465 (.4) 4.3 ------ ------ ------ Total energy sales 25,708 25,900 25,910 (.7) - ====== ====== ====== Interchange Energy deliveries 822 7,063 1,784 (88.4) - ====== ====== ====== By Geographic Area Maryland, including wholesale 15,601 15,763 15,594 (1.0) 1.1 District of Columbia 10,107 10,137 10,316 (.3) (1.7) ------ ------ ------ Total energy sales 25,708 25,900 25,910 (.7) - ====== ====== ====== - ----------------------------------------------------------------- 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. Kilowatt-hour sales in 1996 remained relatively unchanged from 1995. Kilowatt-hour sales were affected by a .6% increase in the average number of customers and increased usage of electricity during the blizzard-like conditions in the first quarter of 1996, and were partially offset by decreased usage of electricity during the cooler than average summer months of 1996. Cooling degree hours in 1996 were 19% and 17% below the 1995 and 20-year average, respectively. Assuming future weather conditions approximate historical averages, the Company expects its compound annual growth in kilowatt-hour sales to range between 1% and 2% over the next decade. The 1997 summer peak demand of 5,689 megawatts occurred on June 25, 1997. This compares with the 1996 summer peak demand of 5,288 megawatts, and the all-time summer peak demand of 5,769 megawatts which occurred in July 1991. The Company's present 7 generation capability, excluding short-term capacity transactions, is 6,806 megawatts. In addition, the Company had approximately 265 megawatts available from its dispatchable Energy Use Management (EUM) programs to meet the 1997 summer peak demand. Based on average weather conditions, the Company estimates that its peak demand will grow at a compound annual rate of approximately 1.5%, reflecting continuing success with DSM and EUM programs and anticipated service area growth trends. The 1996-1997 winter season peak demand of 4,632 megawatts was 7.5% 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 - ----------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------- (Millions of Dollars) Fuel expense $319.6 $327.8 $355.4 ------ ------ ------ Purchased energy PJM 86.6 114.6 79.4 Other 114.0 221.4 114.2 ------ ------ ------ Total purchased energy 200.6 336.0 193.6 ------ ------ ------ Fuel and purchased energy $520.2 $663.8 $549.0 ====== ====== ====== Capacity purchase payments $150.9 $125.8 $125.8 ====== ====== ====== - ----------------------------------------------------------------- Net System Generation and Purchased Energy were as follows. - ----------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------- (Millions of Kilowatt-hours) Net system generation 18,322 18,041 19,234 ====== ====== ====== Purchased energy 9,371 16,157 9,755 ====== ====== ====== - ----------------------------------------------------------------- 8 Although net generation increased by 1.6% during 1997, fuel expense decreased due to the timing of fuel billed to customers through the Company's fuel rates. The 1996 decrease in fuel expense reflects a decrease of 6.2% in net generation, partially offset by an increase in the system average fuel cost summarized below. The Company's unit costs of fuel burned and the percentages of system fuel requirements obtained from coal, oil and natural gas were as 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) 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 1995 85.4 6.1 8.5 1.60 3.22 2.10 1.74 - ----------------------------------------------------------------- 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 1996 system average unit fuel cost increased by approximately 3% which was primarily the result of the increase in the cost of residual oil and an increase in the percent of residual oil contribution to the fuel mix. The Company's major cycling and certain peaking units can burn either natural gas or oil, adding flexibility in selecting the most cost-effective fuel mix. The increase in the percent of gas burned in 1997 reflects the decreased price of gas and the decreased usage of higher-cost oil. The decrease in the percent of gas burned in 1996 reflects the increased price of gas and the increased usage of lower-cost coal. The Company's generating and transmission facilities are interconnected with those of other transmission owners in the PJM power pool and other utilities. Historically, the pricing of most PJM-dispatched internal economy energy transactions was based upon "split savings" whereby such energy was priced halfway between the cost that the purchaser would incur if the energy were supplied by its own sources and the cost of production to the company actually supplying the energy. In April 1997, PJM implemented a "bid-based" energy market, where companies offer energy at prices based on cost, and transactions occur at the market's marginal clearing price. 9 On November 25, 1997, the FERC conditionally approved a PJM restructuring plan which, among other things, established an independent system operator (ISO). The ISO began operation on January 1, 1998, and is responsible for system operations and regional transmission planning. PJM's revised transmission tariff will become effective on April 1, 1998. The Commission indicated that the independent body that operates the ISO may also operate the PJM power exchange. Transmission is now priced at a single rate based on the cost of the transmission system where the generating capacity is delivered, instead of the prior practice of paying separate rates for each transmission system used. The Commission also approved locational marginal pricing for transmission congestion control. The Commission delineated the principles necessary for forming ISO's in its Order No. 888 issued in April 1996. (See Restructuring of the Bulk Power Market discussion below). In addition to interchange with PJM, the Company is actively participating in the emerging bilateral energy sales marketplace. 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. Over 40 utilities and marketers have executed service agreements allowing them to arrange purchases under this tariff. The Company has also executed service agreements allowing it to purchase energy under other market participants' power sales tariffs. These agreements greatly expand the opportunities for economic transactions. The Company continues to purchase energy from Ohio Edison under the Company's 1987 long-term capacity purchase agreements with Ohio Edison and Allegheny Energy, Inc. (AEI, formerly Allegheny Power System). Pursuant to this agreement, the Company is purchasing 450 megawatts of capacity and associated energy through the year 2005. In August 1996, the Company began purchasing 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 also purchases energy from the Northeast Maryland Waste Disposal Authority under an avoided cost-based purchase agreement. In November 1997, the Company agreed to purchase the 32-megawatt rated capacity of this facility for the period November 1, 1997 to December 31, 1998. This purchase facilitated the sale of 35 megawatts of capacity to Northeastern Utility Service Company (NUSCO). The capacity expense under these agreements, including an allocation of a portion of Ohio Edison's fixed operating and maintenance costs, was $145.2 million for 1997 and is estimated at $143 million for 1998. Commitments under these agreements are estimated at $198 million for 1999, $201 million for 2000, and $207 million for 2001 and 2002. 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 10 Maryland, purchased capacity costs are recovered in base rates. Accordingly, the Company will seek recovery of future changes in the levels of these costs through a base rate application to the Maryland Commission. The Company has a purchase agreement with Southern Maryland Electric Cooperative, Inc. (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 power sales tariff also allows for the sale of generating capacity on a short-term basis. The Company sold capacity to PECO Energy Company in the amount of 150 megawatts during January 1997 and 100 megawatts for the period February through May 1997. In addition, the Company is selling capacity to Delmarva Power & Light Company in the amount of 100 megawatts for the period June 1, 1997, through May 31, 1998; and to GPU, Inc. in the amount of 130 megawatts for the period August 1, 1997, through December 31, 1997. The Company is also selling 35 megawatts of capacity to NUSCO for the period November 1, 1997 through December 31, 1998. This sale was facilitated by the purchase of 32 megawatts of capacity from the Northeast Maryland Waste Disposal Authority. Revenues from capacity and energy transactions totaled approximately $11.1 million, $151.4 million and $22.9 million in 1997, 1996 and 1995, respectively, and are included as components of interchange deliveries. As electricity becomes more actively traded as a commodity, the bulk power market is developing methods for traders to hedge against price volatility. New York Mercantile Exchange (NYMEX) futures contracts for electricity began trading in 1996 for delivery at the California-Oregon border and at Palo Verde Substation in Arizona. The NYMEX has approved a futures contract with PJM delivery, and is preparing to submit the contract to the Commodities Futures Trading Commission for approval. This futures contract, anticipated to begin in 1998, will have a greater relevance to transactions in the mid-Atlantic marketplace. 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 contracts-for-differences to exchange variable prices for a fixed price. The proposed mid-Atlantic energy market is expected to feature a secondary market in transmission congestion hedging. In the future, the Company expects to participate 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 $315.5 million for 1997. These expenses increased by $.7 million (.2%) in 1997, principally due to increases in electric plant maintenance expense, partially offset by reduced labor and benefits costs. These expenses decreased by $2 million (.6%) in 1996, including the $1.8 million and $.9 million paid on January 5, 1996, and June 7, 1996, respectively, to union members as part of the 1995 Labor Agreement between the Company and Local 1900 of the International Brotherhood of Electrical Workers. These expenses increased by $18.2 million (6.1%) in 1995, including $15.2 million related to the December 1994 sale and leaseback of the Company's control center system. The Company's budget and cost control disciplines have resulted in a 16% decline in the number of Company employees since 1994. In addition, utility operating results for 1995 were affected by a nonrecurring charge of $7.4 million in January 1995 for one-time operating costs associated with the Company's successful Voluntary Severance Program, which has provided annual savings in operating and construction costs of approximately $15 million. The Company has implemented, through an internal Task Force, a 4-phase approach to accommodate the year 2000. The phases being addressed are: Corporate Application Compliance which includes all large core business systems; Business Partners' Systems and Vendor System Verification which is intended to ensure all suppliers are in compliance with year 2000 processing; End-user Computing Systems which are all systems which are not considered core business systems but contain date calculations; and Non-Information Technology Processes that include all operating and control systems. The Task Force has developed a database to identify and track the progress of work on each phase. The preliminary target date for overall completion of these phases is mid 1999. The Company is required to charge to expense, as incurred, internal and external costs specifically associated with modifying internal-use computer software for the year 2000, in accordance with a July 1996 pronouncement of the Emerging Issues Task Force of the Financial Accounting Standards Board. The costs of expected modifications to be made, principally in the next two years, will be approximately $10 million. 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. 12 Depreciation and Amortization Expense, Income Taxes and Other Taxes - ------------------------------------------------------- Depreciation and amortization expense increased by $9 million (4%) in 1997 due to additional investment in property and plant. Depreciation and amortization expense increased by $17.5 million (8.5%) and $25.5 million (14.2%) in 1996 and 1995, respectively, due to additional investment in property and plant and amortization of increased amounts of conservation costs associated with the Company's DSM program. The decrease in income taxes in 1997 reflects lower taxable operating income. The increase in income taxes in 1996 and 1995, reflects higher taxable operating income. Other taxes increased by $1.4 million (.7%) in 1997, and decreased by $2.3 million (1.2%) and $3.4 million (1.6%) in 1996 and 1995, respectively. The increase in 1997 reflects increases and partially offsetting decreases in the levels of plant investment and operating revenue, respectively, upon which taxes are based. The decreases in 1996 and 1995 reflect the reduction in county fuel-energy tax rates. Other Income, Allowance for Funds Used During Construction and Capital Cost Recovery Factor, and Utility Interest Charges - -------------------------------------------------------------- Other income reflects net earnings (loss) from PCI of $17.1 million in 1997, $16.9 million in 1996 and $(124.4) million in 1995. See the Nonutility Subsidiary discussion below and the discussion included in Note (15) of the Notes to Consolidated Financial Statements, Selected Nonutility Subsidiary Financial Information. As discussed above, in December 1997, the Company wrote off cumulative deferred Merger related costs totaling $52.5 million. Other income includes, in "Other, net", credits of $19.9 million for income taxes associated with the Merger write- off. Other income also reflects credits for the equity components of the Allowance for Funds Used During Construction (AFUDC) accrued on the Company's Construction Work In Progress expenditures not in rate base and the Capital Cost Recovery Factor (CCRF) accrued on certain pollution control expenditures related to Clean Air Act (CAA) compliance. AFUDC equity totaled $1 million in 1997, $1.4 million in 1996 and $1.5 million in 1995; CCRF equity credits totaled $5.7 million in 1997, $5.2 million in 1996 and $4.7 million in 1995. CCRF accruals on unamortized District of Columbia DSM costs not in rate base, totaling $5.4 million in 1997, $4.1 million in 1996 and $4.8 million in 1995, are also reflected in "Other, net". Utility interest charges were relatively stable during the three-year period 1995 through 1997, 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 7.56% at the beginning of 1995 to 7.33% at the end of 1997. Utility interest charges were offset 13 by both the debt component of AFUDC which totaled $3.8 million in 1997, $3.9 million in 1996 and $7.5 million in 1995; and by the debt component of Clean Air Act CCRF which totaled $4.1 million in 1997, $3.6 million in 1996 and $3.3 million in 1995. CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- The Company's total investment in property and plant, at original cost, was $6.5 billion at year-end 1997. Investment in property and plant construction, net of AFUDC and CCRF, was $610.8 million for the period 1995 through 1997. Internally generated cash from utility operations, after dividends, totaled $503.7 million for the period 1995 through 1997. Sales of First Mortgage Bonds, Medium-Term Notes and Common Stock during the period 1995 through 1997 provided a total of $474.9 million. During the years 1995 through 1997, the Company retired $296.8 million in outstanding long-term securities, including refinancings, scheduled debt maturities and sinking fund retirements. Interim financing was provided principally through the issuance of short-term commercial promissory notes. During the three-year period 1998 through 2000, capital resources of $201 million ($52 million in 1998) 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 $805 million is expected to be available from depreciation and amortization charges and income tax deferrals over the three-year period of which approximately $270 million is the 1998 portion. In October 1997, the Company sold $175 million principal amount of First Mortgage Bonds. Proceeds were applied to refund short-term debt incurred to finance ongoing construction and operating activities and to pay at maturity, in July and August 1997, $50 million principal amount of medium-term notes; and to pay at maturity $50 million principal amount of First Mortgage Bonds due February 15, 1998. See the discussion included in Notes (7) and (10) of the Notes to Consolidated Financial Statements, Common Equity and Long-Term Debt, respectively, for additional information. Total annualized interest costs for all utility long-term debt outstanding at December 31, 1997, was $132.6 million, compared with $133 million and $127.9 million at December 31, 1996 and 1995, respectively. The Company reduced its Maryland fuel rate by 9.5% effective August 28, 1997. Included in the reduction was an adjustment for a deferred fuel amortization charge to refund over a twelve month period approximately $20.7 million of previously overrecovered fuel costs incurred through June 30, 1997. The Maryland 14 Commission order approving the reduction became final on December 13, 1997. The Company expects to apply for an increase in the Maryland fuel rate in early 1998. Dividends on common stock were $196.6 million in 1997 and 1996 and $196.5 million in 1995. 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. Although the Company has no current plans to change the dividend, there can be no assurance that the $1.66 dividend rate will be in effect in the future. Dividends on preferred stock were $16.6 million in 1997 and 1996 and $16.9 million in 1995. The embedded cost of preferred stock was 6.44% at December 31, 1997, 6.41% at December 31, 1996 and 6.43% at December 31, 1995. The Company's capitalization ratios (excluding nonutility subsidiary debt), at December 31, 1997, are presented below. - ----------------------------------------------------------------- Excluding Including Amounts Due Amounts Due In One Year In One Year - ----------------------------------------------------------------- Long-term debt 47.2% 45.1% Redeemable serial preferred stock 3.5 3.3 Serial preferred stock 3.1 3.0 Common equity 46.2 44.2 Short-term debt and amounts due in one year - 4.4 ----- ----- Total capitalization 100.0% 100.0% ===== ===== - ----------------------------------------------------------------- Year-end 1997 outstanding utility short-term indebtedness totaled $131.4 million compared with $131.4 million and $258.5 million at the end of 1996 and 1995, respectively. The Company maintains 100% line of credit back-up in the amount of $180 million, for its outstanding commercial promissory notes, which was unused during 1997, 1996 and 1995. Conservation - ------------ The Company's DSM and EUM programs are designed to curb growth in demand in order to defer the need for construction of additional generating capacity and to cost-effectively increase the efficiency of energy use. To reduce the near-term upward 15 pressure on customer rates and bills, the Company has, since 1994, phased out several conservation programs and reduced rebate levels for others. By narrowing its conservation offerings and limiting conservation spending, the Company expects to continue to encourage its customers to use energy efficiently without significantly increasing electricity prices. In a June 1995 order, the District of Columbia Public Service Commission adopted a DSM spending cap for the four-year period 1995 through 1998. The Company continues to manage its existing portfolio of DSM programs to ensure that the costs of these programs do not exceed the spending limit. Remaining allowable expenditures under the DSM spending cap totaled $10 million at December 31, 1997. Investment in District of Columbia DSM programs totaled approximately $5 million in 1997. These DSM costs are amortized over 10 years with an accrued return on unamortized costs. In June 1995, the Commission adopted a base rate surcharge for the recovery of actual DSM costs prudently incurred since June 30, 1993; prior to this decision, DSM costs had been considered in base rate cases. This surcharge includes both a conservation expenditure component and a component for recovering certain expenditures associated with complying with the CAA Amendments of 1990. The conservation component is scheduled to be updated annually in the spring of each year, while the CAA component is updated quarterly. In June 1997, the Company filed an Application for Authority with the District of Columbia Public Service Commission requesting approval for an updated conservation component reflecting recoverable DSM costs expended during 1995 and 1996. The Application, which superseded an Application filed in June 1996, proposed a rate which would increase annual revenue by approximately $9 million. No action has been taken by the District of Columbia Public Service Commission on the revised surcharge rate. During 1997, the Company invested approximately $24 million in Maryland DSM programs. The Company recovers the costs of Maryland DSM programs through a base rate surcharge which amortizes costs over a five-year period and permits the Company to earn a return on its DSM investment while receiving compensation for lost revenue. In addition, when energy savings exceed annual goals, the Company earns a bonus. The Company was awarded a bonus of $1.6 million in 1997, based on 1996 performance, which followed bonuses of $8.9 million in 1996, based on 1995 performance, and $8.7 million in 1995, based on 1994 performance. Maryland DSM program goals for 1996 were reduced to reflect lower DSM expenditures, consequently, the performance bonus in 1997 was significantly lower than amounts awarded for performance in prior years. 16 In 1997, approximately 160,000 customers participated in continuing EUM programs which cycle air conditioners and water heaters during peak periods. In addition, the Company operates a commercial load program which 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 nearly 725 megawatts have been achieved to date from DSM and EUM programs and that additional peak load reductions of approximately 300 megawatts will be achieved in the next five years. The Company also estimates that, in 1997, 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 that encourage the efficient use of electric energy and reduce the need to build new generating facilities total $136 million ($36 million in 1998). Construction and Generating Capacity - ------------------------------------ Construction expenditures, excluding AFUDC and CCRF, totaled $217 million in 1997 and are projected to total $845 million for the five-year period 1998 through 2002, which includes approximately $75 million of CAA expenditures. In 1998, construction expenditures are projected to total $175 million, which includes $10 million of estimated CAA expenditures. The Company plans to finance its construction program primarily through funds provided by operations. The Company has been purchasing energy from a 32-megawatt municipally financed resource recovery facility in Montgomery County, Maryland, which began commercial operation in August 1995. In November 1997, the Company agreed to purchase the 32- megawatt rated capacity of the facility for the period November 1, 1997 to December 31, 1998. This purchase facilitated the sale of 35 megawatts to NUSCO. In addition, the Company has a 25-year agreement with Panda for a 230-megawatt gas-fueled combined-cycle cogeneration project in Prince George's County, Maryland. This facility achieved full commercial operation in October 1996. In October 1997, the Company restructured its agreement with Panda to resolve certain disputes regarding capacity and energy payment rates for the facility. In exchange for an adjustment in capacity payment rates and a reduction in the present value of capacity payments over the term of the agreement, the Company accrued a one-time payment to Panda of approximately $3.9 million at December 31, 1997. Other features of the settlement allow Panda 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 17 for the right to broker capacity sales, as well as a fee based on actual energy sales. The Company projects that existing contracts for nonutility generation and the Company's commitment to conservation will provide adequate reserve margins to meet customers' needs well beyond the year 2000. CLEAN AIR ACT - ------------- The Company has implemented cost-effective plans for complying with Phase I of the Acid Rain portion of the CAA which requires the reduction of sulfur dioxide and nitrogen oxides emissions to achieve prescribed standards. Boiler burner equipment for nitrogen oxides emissions control has been installed and the use of lower-sulfur coal has been instituted at the Company's Phase I affected stations, Chalk Point and Morgantown. Anticipated capital expenditures for complying with the second phase of the CAA total $73 million over the next five years. If economical, continued use of lower-sulfur coal, cofiring with natural gas and the purchase of sulfur dioxide (SO2) emission allowances is expected. Nitrogen oxides emissions reductions will be achieved by installing new boiler burner controls and equipment at the Company's Dickerson Generating Station. 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. Further, the U.S. Environmental Protection Agency (EPA) has issued proposed rules for reducing interstate transport of ozone. These provisions are likely to result in further nitrogen oxides emissions reductions from the Company's boilers; however, the extent of reductions and associated costs cannot be predicted at this time. The Company owns a 9.72% undivided interest in the Conemaugh Generating Station located in western Pennsylvania. Nitrogen oxides emissions reduction equipment and flue gas desulfurization equipment have been installed at the station 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. 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 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 18 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 1995 through 1997 are shown below. - ----------------------------------------------------------------- District of Year Total Maryland Columbia Wholesale - ----------------------------------------------------------------- (Millions of Dollars) 1997 $24.0 $24.0 $ - $ - 1996 (2.0) - - (2.0) 1995 30.2 - 27.9 2.3 ----- ----- ----- ----- $52.2 $24.0 $27.9 $ 0.3 ===== ===== ===== ===== - ----------------------------------------------------------------- Maryland - -------- On November 25, 1997, pursuant to a settlement agreement, the Maryland Public Service Commission authorized a $24 million, or 2.6%, increase in base rate revenues effective with bills rendered on and after November 30, 1997. Of the $24 million increase in base rates, approximately $12 million will replace CCRF accrued on CAA expenditures and, therefore, will have no effect on future net income levels. The increased rates afford the Company the opportunity to recover capacity costs associated with the Panda agreement previously approved by the Maryland Commission. Capacity payments to Panda commenced in January 1997 and totaled $25.3 million in 1997, of which the Maryland portion was approximately $13 million. In connection with the settlement agreement, no determination was made with respect to rate of return for purposes of setting rates; however, a rate of return of 9% will be used by the Company, beginning in December 1997, for purposes of computing AFUDC and CCRF. Effective June 6, 1997, the Maryland DSM surcharge tariff was lowered, which will reduce annual revenues by approximately $17 million, reflecting the Company's efforts to narrow conservation program offerings and limit conservation spending. The surcharge includes provisions for the recovery of lost revenue, amortization of pre-1997 actual program expenditures plus the initial amortization of 1997 projected program costs, a CCRF on unamortized program balances and an incentive of $1.6 million awarded for achieving specified 1996 energy goals. 19 Previously, incentives of $8.9 million and $8.7 million were awarded for achieving 1995 and 1994 energy goals, respectively. Maryland energy goals for 1996 had been reduced to reflect lower DSM expenditures, consequently, the performance bonus awarded in 1997 was lower than those awarded in prior years. District of Columbia - -------------------- The District of Columbia Public Service Commission authorized a $27.9 million, or 3.8%, increase in base rate revenue effective in July 1995. The authorized rates 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. In addition, the Commission approved the Company's Least- Cost Plan filed in June 1994. A four-year DSM spending cap for the period 1995-1998 was approved, consistent with the Company's proposal to narrow the scope of DSM activities by discontinuing operation of certain DSM programs and by reducing expenditures on the remaining programs. This will enable the Company to implement cost-effective DSM programs while limiting the impact of such programs on the price of electricity. An Environmental Cost Recovery Rider (ECRR) was approved to provide for full cost recovery of actual DSM program expenditures, through a billing surcharge. Costs will be amortized over 10 years, with a return on unamortized amounts by means of a CCRF computed at the authorized rate of return. The initial rate, which reflects actual costs expended from July 1993 through December 1994, resulted in additional annual revenue of approximately $15 million. Although the Commission denied the Company's request to recover "lost revenue" due to DSM programs, through the surcharge, a process has been established whereby the Company can seek recovery of lost revenue in a separate proceeding. The Commission also increased the time period for filing Least-Cost Planning cases from two to three years. In June 1997, the Company filed an Application for Authority with the Commission to revise its ECRR. In the Application, which superseded an Application filed in June 1996, the proposed rate seeks recovery of actual costs expended during 1995 and 1996, and is expected to increase annual revenue by approximately $9 million. No action has been taken by the Commission on the revised ECRR. Subsequent rate updates are scheduled to be filed annually on June 1 to reflect the prior year's actual costs, subject to the annual surcharge recovery limit within the four-year spending cap for the period 1995-1998 (amounts spent in excess of the annual surcharge recovery limit, but within the four-year spending cap, are deferred for future recovery). Remaining allowable expenditures under the spending cap totaled $10 million at December 31, 1997. Pre-July 1993 DSM costs receive base rate treatment. 20 Wholesale - --------- The Company has a 10-year full service power supply contract with the SMECO, a wholesale customer. The contract period is to be 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 full service obligation can be reduced by SMECO by up to 20% of its annual requirements with a five-year advance notice for each such reduction. SMECO rates were increased by $2.3 million effective January 1, 1995. Pursuant to an agreement with SMECO for the years 1996 through 1998, a rate reduction of $2 million from the 1995 rate level became effective January 1, 1996, and an additional $2.5 million rate reduction became effective January 1, 1998. SMECO has agreed not to give the Company a notice of reduction or termination of service prior to December 15, 1998. COMPETITION - ----------- The electric utility industry is subject 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. 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 which compare favorably with regional and national averages. Pursuant to an August 1995 order in a generic proceeding dealing with electric industry structure and the advent of competition, the Maryland Public Service Commission found that competition at the wholesale level holds the greatest potential for producing significant benefits, while competition at the retail level would carry many potential problems with difficult- to-find solutions. In October 1996, the Maryland Commission reopened the generic proceeding to review regulatory and competitive issues affecting the electricity industry. The Commission cited the evolving nature of the electric industry as the basis for continuing its investigation. The Commission also directed its Staff to submit a report containing, among other things, recommendations regarding regulatory and competitive issues facing the electric industry in Maryland. In May 1997, the Commission Staff issued a report proposing a three-step process 21 for implementing customer choice, affording all Maryland customers the option of choosing their supplier of electricity by April, 2001. On December 3, 1997, the Maryland Commission issued an Order outlining steps toward a competitive electric generation market. On December 31, 1997, the Commission issued a second Order that established later dates for the phased-in implementation of competition and also suspended all other dates in its December 3, 1997 Order, which scheduled various filings, hearings and discussions concerning how competition would be implemented. Pursuant to the revised order, 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. Maryland utilities will be given the opportunity to recover verifiable and prudently incurred stranded costs which cannot be mitigated or reduced; utilities will be required to file a breakdown of stranded costs including a proposed method for cost recovery at a date to be set by the Commission. The Company has not completed its analysis of possible stranded costs and alternatives for mitigating or reducing such costs at the present time. The Commission will consider proposals to establish a competitive transition charge to address stranded costs. In addition, 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. Moreover, the Commission did not order the divestiture or corporate unbundling of generating assets; however, the Commission will consider these options as part of its review of market power studies required to be filed by Maryland electric utilities at a date to be set by the Commission. On January 2, 1998, the Company filed an application for rehearing and clarification of the Commission's December 3, 1997 Order. It remains unclear whether the Commission has authority to move forward without the explicit approval of the Maryland legislature or whether full retail competition can occur without Maryland legislative action concerning the many issues which are integral to the Commission's plan. For example, the Commission recognizes the need for tax reform to "level the playing field" for Maryland utilities, and has requested the legislature to enact the necessary legislation. Also, the Commission believes that fuel adjustment clauses are incompatible with the workings of a competitive generation market and has requested that legislation be enacted to discontinue use of fuel adjustment clauses in the future. Additionally, the Commission has requested that the necessary legislation be enacted to permit 22 price cap regulation and to otherwise materially depart from cost of service regulation with respect to the purchase and generation of electricity. The Commission has not proposed any changes to the form of regulation currently applicable to the recovery of costs associated with the distribution of electricity. Also, the Commission proposed the establishment of statewide roundtables to address issues such as provision of metering and billing services, consumer protection and DSM. The Company reaffirms its full support for customer choice for Maryland electric customers, and has provided key principles to be used as guidelines for its introduction. These principles include the concept that Maryland companies 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. In late 1995 the District of Columbia Public Service Commission initiated a proceeding to investigate issues regarding electricity industry structure and competition. In September 1996, the Commission issued an order designating the issues to be examined in the proceeding. Initial and reply comments regarding the designated issues were filed with the Commission in early 1997. To date, no decisions have been rendered. Based on the regulatory framework in which it operates, the Company currently applies the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" in accounting for its 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 business, 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 $29 million and $21 million at December 31, 1997 and 1996, respectively. Under traditional regulation, utilities were 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 23 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 purchase power obligations; and regulatory assets and obligations incurred in accordance with SFAS No. 71. The Company fully expects to be provided an opportunity to recover its stranded costs. RESTRUCTURING OF THE BULK POWER MARKET - -------------------------------------- In April 1996, the FERC issued its Final Rulemaking Orders No. 888 and No. 889. Both rulemakings address achieving greater competition in the wholesale energy market through open access to transmission on a comparable basis. The Commission required that power pools such as PJM must also comply with these Orders. Order No. 888 required utilities to file open access transmission tariffs. 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. On January 3, 1997, the Company's OASIS became operational. Subsequently, on April 1, 1997, PJM implemented an OASIS on behalf of the PJM transmission owners which replaced the Company's OASIS. Order No. 889 also required the Company to establish a code of conduct that complies with FERC's prescribed standards to separate utilities' transmission system operations and wholesale marketing functions. The Company's filed code of conduct became effective on January 3, 1997. On November 25, 1997, FERC conditionally approved a PJM restructuring plan, establishing an independent system operator (ISO) to administer transmission service under a PJM control area poolwide transmission tariff and provide open access transmission service on a pool-wide basis. The ISO, which began operation on January 1, 1998, is 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 plan'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 24 transmission capability. This method is based on price differences in energy at the various locations on the transmission system. The Company was instrumental in pursuing this restructuring plan. 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. NEW ACCOUNTING STANDARDS - ------------------------ See the discussion included in Note (1) of the Notes to Consolidated Financial Statements, 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 1997, 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. 25 NONUTILITY SUBSIDIARY - --------------------- RESULTS OF OPERATIONS - --------------------- PCI's earnings for 1997 were $17.1 million ($.14 per share), compared with net earnings of $16.9 million ($.14 per share) in 1996 and a net loss of $124.4 million ($1.05 per share) in 1995. During 1997, PCI sold its remaining aircraft held for disposal, resulting in a $2 million pre-tax ($1.3 million after-tax) charge to earnings. As a result of joint venture operations during 1997, PCI's obligation for previously accrued deferred income taxes was reduced, resulting in after-tax earnings of $7.4 million after provision for transaction costs. PCI's earnings for 1997 also include capital gains totaling $4.5 million, net of tax, related primarily to tender offers accepted by PCI which reduced the cost basis of its preferred stock portfolio by $83 million since year end 1996. Proceeds were used to pay down debt which resulted in a decrease in interest expense from 1996. On December 18, 1997, PCI and RCN Telecom Services, Inc. (RCN) of Princeton, New Jersey signed the definitive agreements forming a joint venture known as Starpower Communications, L.L.C. to provide a package of local and long distance telephone, cable television, high speed Internet and other telecommunications services to residents and businesses in the Washington, D.C./ Baltimore/Northern Virginia metropolitan region. The joint venture is equally owned and managed by PCI and RCN. PCI and RCN each will invest up to $150 million over a three-year period to build out, market and provide these services over an advanced fiber optic network. PCI's investment in the joint venture will be funded through cash from operations and borrowings under its Medium-Term Note facility. PCI expects that the joint venture will incur operating losses initially, as it develops and expands its network and customer base. Start-up costs incurred by PCI relating to the telecommunications business have been expensed. In 1997, PCI generated income primarily from its leasing activities and securities investments. Income from leasing activity, which includes rental income, gains on asset sales, interest income and fees totaled $75.6 million in 1997, compared to $91.7 million in 1996 and $100.6 million in 1995. The decrease in income from leasing activity during 1997 was primarily due to aircraft sales, resulting in lower rental income. The decrease in 1996 compared to 1995 was primarily the result of non-recurring fee income earned in 1995. PCI's marketable securities portfolio contributed pre-tax income of $28.6 million in 1997, $33.7 million in 1996 and $36.1 million in 1995. The decreases in income from marketable securities were primarily due to decreases in dividend income as a result of 26 reductions in the preferred stock portfolio since 1995. Income from marketable securities included net realized gains of $6.9 million in 1997, $3.6 million in 1996 and $.4 million in 1995. Other income totaled $20.9 million in 1997 compared with a loss of $10.4 million in 1996 and a loss of $2.3 million in 1995. The increase in other income for 1997 was primarily the result of $22.5 million in revenue earned from investments made by PEPCO Enterprises, Inc. (PEI), a wholly-owned operating subsidiary which the Company contributed to PCI in the second quarter of 1996. Through PEI, PCI has business interests and investments in the energy industry, including liquefied natural gas peak storage and pipeline facilities, and an underground cable construction and maintenance company. PCI's other principal operating subsidiaries are Pepco Communications L.L.C., which targets the telecommunications business sector and holds a 50% interest in Starpower Communications, and Pepco Services, Inc. which is an energy services company primarily targeting large commercial and industrial energy users inside and outside PEPCO's retail service territory. Other income also includes pre-tax writedowns of $29 million ($18.8 million after-tax) taken in 1996 related to PCI's investments in solar energy projects, real estate and oil and natural gas, and pre-tax writedowns taken in the fourth quarter 1997 related to real estate of $10 million ($6.5 million after- tax). Expenses before income taxes, which include interest, depreciation and operating, and administrative and general expenses totaled $139.9 million, $152.7 million and $344.6 million for years ended 1997, 1996 and 1995, respectively. The decrease in expenses before income taxes for 1997 compared to 1996 and 1995 was primarily due to a $2 million pre-tax loss on assets held for disposal in 1997 compared to a $12.7 million pre- tax loss in 1996 and a $170.1 million pre-tax loss in 1995. Interest expense also decreased over the three-year period due to a decrease in debt outstanding as proceeds from the sales of aircraft and marketable securities were used to pay down debt. The decrease in expenses before income taxes in 1997 was partially offset by operating expenses of $21.8 million for PEI and other new business entities. PCI had income tax credits of $31.9 million in 1997, $54.6 million in 1996 and $85.7 million in 1995. The decrease in income tax credits was primarily due to the $170.1 million aircraft writedown taken in May 1995 and deferred tax reversals of $30.8 million in 1996 compared to $10.1 million of deferred tax reversals in 1997. 27 CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- PCI has a $302.5 million securities portfolio, consisting primarily of fixed-rate electric utility preferred stocks. During 1997, PCI reduced the cost basis of its marketable securities portfolio by $83 million primarily as the result of calls and acceptance of tender offers (approximately $118.1 million) offset by purchases of $35.1 million. The reduced size of the preferred stock portfolio lessens the impact of future fluctuations in interest rates. Proceeds from securities activity during 1997 were used to pay down short-term debt. During the first quarter of 1997, PCI received $25.8 million in cash proceeds from the sale of notes receivable from World Airways and recorded an after-tax charge to earnings of $.4 million. PCI also received $15.7 million in cash proceeds for the early redemption of a note receivable related to the 1996 sale of an aircraft engine leasing subsidiary. During the third quarter of 1997, PCI received $12.9 million for the sale of notes receivable from Continental Airlines and recorded an after-tax gain of $.9 million. The sale and early redemption of the notes further reduce PCI's exposure to the ongoing credit risk associated with the airline industry as well as the inherent uncertainty regarding the future value of the aircraft which secured the repayment of the notes. PCI had short-term debt outstanding of $7.7 million at December 31, 1997, compared to $51.7 million at December 31, 1996. During 1997, PCI issued $40 million in long-term debt, including non-recourse debt, and debt repayments totaled $205.8 million. At December 31, 1997, PCI had $196 million available under its Medium-Term Note Program and $400 million of unused bank credit lines. 28 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 of cash flows present fairly, in all material respects, the financial position of Potomac Electric Power Company and its subsidiary at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, 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/ Price Waterhouse LLP Washington, D.C. January 16, 1998 29 Consolidated Statements of Earnings Potomac Electric Power Company and Subsidiary
- --------------------------------------------------------------------------------------------------------- For the year ended December 31, 1997 1996 1995 - --------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Revenue (Note 2) Operating revenue $ 1,810,829 $ 1,834,857 $ 1,822,432 Interchange deliveries 52,681 175,454 53,670 ----------- ----------- ----------- Total Revenue 1,863,510 2,010,311 1,876,102 ----------- ----------- ----------- Operating Expenses Fuel 319,619 327,792 355,453 Purchased energy 200,562 335,978 193,592 ----------- ----------- ----------- Fuel and purchased energy 520,181 663,770 549,045 Capacity purchase payments (Note 13) 150,912 125,786 125,769 Other operation 220,289 223,326 224,030 Maintenance 95,252 91,524 92,859 Depreciation and amortization 232,042 223,016 205,490 Income taxes (Note 4) 117,731 134,085 128,460 Other taxes (Note 5) 201,720 200,365 202,708 ----------- ----------- ----------- Total Operating Expenses 1,538,127 1,661,872 1,528,361 ----------- ----------- ----------- Operating Income 325,383 348,439 347,741 ----------- ----------- ----------- Other (Loss) Income Nonutility subsidiary (Note 15) Income 125,140 114,966 134,493 Loss on assets held for disposal (2,022) (12,744) (170,078) Expenses, including interest and income taxes (106,037) (85,328) (88,812) ----------- ----------- ----------- Net earnings (loss) from nonutility subsidiary 17,081 16,894 (124,397) Allowance for other funds used during construction and capital cost recovery factor 6,708 6,572 6,155 Write-off of merger costs (Note 13) (52,533) - - Other, net 24,021 4,458 682 ----------- ----------- ----------- Total Other (Loss) Income (4,723) 27,924 (117,560) ----------- ----------- ----------- Income Before Utility Interest Charges 320,660 376,363 230,181 ----------- ----------- ----------- Utility Interest Charges Interest on debt 146,703 146,939 146,558 Allowance for borrowed funds used during construction and capital cost recovery factor (7,873) (7,536) (10,768) ----------- ----------- ----------- Net Utility Interest Charges 138,830 139,403 135,790 ----------- ----------- ----------- Net Income 181,830 236,960 94,391 Dividends on Preferred Stock 16,579 16,604 16,851 ----------- ----------- ----------- Earnings for Common Stock $ 165,251 $ 220,356 $ 77,540 =========== =========== =========== Earnings Per Common Share (Note 7) $1.39 $1.86 $.65 Fully Diluted Earnings Per Common Share (Note 7) $1.38 $1.82 $.65 Cash Dividends Per Common Share $1.66 $1.66 $1.66 30
Consolidated Balance Sheets Potomac Electric Power Company and Subsidiary
- --------------------------------------------------------------------------------------------- December 31, Assets 1997 1996 - --------------------------------------------------------------------------------------------- (Thousands of Dollars) Property and Plant - at original cost (Notes 6 and 10) Electric plant in service $ 6,392,750 $ 6,232,049 Construction work in progress 94,309 62,469 Electric plant held for future use 4,231 4,152 Nonoperating property 22,824 22,921 ----------- ----------- 6,514,114 6,321,591 Accumulated depreciation (2,027,780) (1,898,342) ----------- ----------- Net Property and Plant 4,486,334 4,423,249 ----------- ----------- Current Assets Cash and cash equivalents 5,630 2,174 Customer accounts receivable, less allowance for uncollectible accounts of $2,102 and $1,298 116,554 128,600 Other accounts receivable, less allowance for uncollectible accounts of $300 32,256 38,490 Accrued unbilled revenue (Note 1) 69,259 70,214 Prepaid taxes 33,740 34,202 Other prepaid expenses 7,599 4,613 Material and supplies - at average cost Fuel 59,434 68,232 Construction and maintenance 68,128 69,541 ----------- ----------- Total Current Assets 392,600 416,066 ----------- ----------- Deferred Charges Income taxes recoverable through future rates, net (Note 4) 238,125 238,467 Conservation costs, net 221,528 233,793 Unamortized debt reacquisition costs 52,745 55,552 Other 148,900 159,139 ----------- ----------- Total Deferred Charges 661,298 686,951 ----------- ----------- Nonutility Subsidiary Assets Cash and cash equivalents 422 804 Marketable securities (Notes 11 and 15) 302,522 377,237 Investment in finance leases (Note 15) 463,592 484,972 Operating lease equipment, net of accumulated depreciation of $153,541 and $117,705 (Note 15) 163,289 199,124 Assets held for disposal - 10,300 Receivables, less allowance for uncollectible accounts of $6,000 64,243 87,745 Other investments 162,865 193,002 Other assets 10,392 12,436 ----------- ----------- Total Nonutility Subsidiary Assets 1,167,325 1,365,620 ----------- ----------- Total Assets $ 6,707,557 $ 6,891,886 =========== =========== 31
- --------------------------------------------------------------------------------------------- December 31, Capitalization and Liabilities 1997 1996 - --------------------------------------------------------------------------------------------- (Thousands of Dollars) Capitalization Common equity (Note 7) Common stock, $1 par value - authorized 200,000,000 shares, issued 118,500,891 and 118,500,037 shares $ 118,501 $ 118,500 Premium on stock and other capital contributions 1,025,167 1,025,187 Capital stock expense (14,958) (14,780) Retained income 734,318 760,285 ----------- ----------- Total Common Equity 1,863,028 1,889,192 Preference stock, cumulative, $25 par value - authorized 8,800,000 shares, no shares issued or outstanding - - Serial preferred stock (Notes 8 and 11) 125,290 125,298 Redeemable serial preferred stock (Notes 9 and 11) 141,000 142,500 Long-term debt (Notes 10 and 11) 1,901,486 1,767,598 ----------- ----------- Total Capitalization 4,030,804 3,924,588 ----------- ----------- Other Non-Current Liabilities Capital lease obligations (Note 13) 160,406 162,936 ----------- ----------- Total Other Non-Current Liabilities 160,406 162,936 ----------- ----------- Current Liabilities Long-term debt and preferred stock redemption due within one year 52,054 152,445 Short-term debt (Note 12) 131,375 131,390 Accounts payable and accrued payroll 118,428 117,810 Capital lease obligations due within one year 20,772 20,772 Taxes accrued 29,158 23,362 Interest accrued 38,307 38,117 Customer deposits 24,838 24,119 Other 67,455 59,016 ----------- ----------- Total Current Liabilities 482,387 567,031 ----------- ----------- Deferred Credits Income taxes (Note 4) 1,029,318 973,642 Investment tax credits (Note 4) 57,308 60,958 Other 19,034 35,658 ----------- ----------- Total Deferred Credits 1,105,660 1,070,258 ----------- ----------- Nonutility Subsidiary Liabilities Long-term debt (Notes 10 and 11) 830,458 996,232 Short-term notes payable (Note 12) 7,685 51,650 Deferred taxes and other (Note 4) 90,157 119,191 ----------- ----------- Total Nonutility Subsidiary Liabilities 928,300 1,167,073 ----------- ----------- Commitments and Contingencies (Note 13) Total Capitalization and Liabilities $ 6,707,557 $ 6,891,886 =========== =========== 32
Consolidated Statements of Cash Flows Potomac Electric Power Company and Subsidiary
- ----------------------------------------------------------------------------------------------------------- For the year ended December 31, 1997 1996 1995 - ----------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities Income from utility operations $ 164,749 $ 220,066 $ 218,788 Adjustments to reconcile income to net cash from operating activities: Depreciation and amortization 232,042 223,016 205,490 Deferred income taxes and investment tax credits 60,544 81,496 51,774 Deferred conservation costs (34,543) (49,404) (104,796) Allowance for funds used during construction and capital cost recovery factor (14,581) (14,108) (16,923) Changes in materials and supplies 10,211 (4,073) 12,418 Changes in accounts receivable and accrued unbilled revenue 19,235 10,539 (15,822) Changes in accounts payable 6,388 13,624 (14,419) Changes in other current assets and liabilities (2,459) 5,859 (1,484) Changes in deferred merger costs 29,009 (24,213) (4,796) Net other operating activities (54,836) (24,461) (40,868) Nonutility subsidiary: Net earnings (loss) 17,081 16,894 (124,397) Deferred income taxes (63,759) (36,398) (49,697) Loss on assets held for disposal 2,022 12,744 170,078 Changes in other assets and net other operating activities 63,716 36,258 83,509 ----------- ----------- ----------- Net Cash From Operating Activities 434,819 467,839 368,855 ----------- ----------- ----------- Investing Activities Total investment in property and plant (231,744) (194,036) (230,675) Allowance for funds used during construction and capital cost recovery factor 14,581 14,108 16,923 ----------- ----------- ----------- Net investment in property and plant (217,163) (179,928) (213,752) Nonutility subsidiary: Purchase of marketable securities (35,103) (19,680) (35,221) Proceeds from sale or redemption of marketable securities 125,000 167,528 27,846 Investment in leased equipment (7,480) (3,056) (154,766) Proceeds from sale or disposition of leased equipment 28,484 3,658 - Proceeds from sale of assets 7,300 34,154 5,966 Purchase of other investments (20,603) (22,998) (3,818) Proceeds from sale or distribution of other investments 18,730 33,867 15,614 Investment in promissory notes - (4,245) (7,955) Proceeds from promissory notes 64,108 16,675 7,977 ----------- ----------- ----------- Net Cash (Used by) From Investing Activities (36,727) 25,975 (358,109) ----------- ----------- ----------- Financing Activities Dividends on common stock (196,615) (196,612) (196,469) Dividends on preferred stock (16,579) (16,604) (16,851) Issuance of common stock - - 4,580 Redemption of preferred stock (1,500) - (78) Issuance of long-term debt 182,267 99,500 188,594 Reacquisition and retirement of long-term debt (151,462) (26,320) (117,465) Short-term debt, net (15) (127,075) 68,865 Other financing activities (1,375) (5,358) (23,611) Nonutility subsidiary: Issuance of long-term debt 40,000 183,000 182,000 Repayment of long-term debt (205,774) (237,102) (275,021) Short-term debt, net (43,965) (171,703) 174,950 ----------- ----------- ----------- Net Cash Used by Financing Activities (395,018) (498,274) (10,506) ----------- ----------- ----------- Net Increase (Decrease) In Cash and Cash Equivalents 3,074 (4,460) 240 Cash and Cash Equivalents at Beginning of Year 2,978 7,438 7,198 ----------- ----------- ----------- Cash and Cash Equivalents at End of Year (Note 14) $ 6,052 $ 2,978 $ 7,438 =========== =========== =========== 33
Notes to Consolidated Financial Statements - ------------------------------------------ (1) 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. Potomac Capital Investment Corporation (PCI), the Company's wholly owned subsidiary, was formed in 1983 to provide a vehicle to conduct the Company's ongoing nonutility investment programs and businesses. Effective April 30, 1996, the Company reorganized its nonutility subsidiaries whereby PEPCO Enterprises, Inc. became a subsidiary of PCI. PCI's principal investments have been in aircraft and power generation equipment, equipment leasing and marketable securities, primarily preferred stock with mandatory redemption features. PCI is also involved with activities, through its subsidiaries, which provide telecommunication and energy services. In addition, PCI has investments in real estate properties in the Washington, D.C. metropolitan area. 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. Based upon the regulatory framework in which it operates, the Company currently applies the provisions of the Statement of Financial Accounting Standards (SFAS) No. 71 entitled "Accounting for the Effects of Certain Types of Regulation" in accounting for capital leases and for certain deferred charges and credits to be recognized in future customer billings pursuant to regulatory authorization, principally deferred income taxes, unamortized conservation costs and unamortized debt reacquisition costs. 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. 34 Certain prior year amounts have been reclassified to conform to the current year presentation. A description of significant accounting policies follows. Principles of Consolidation - --------------------------- The consolidated financial statements combine the financial results of the Company and PCI. 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. In the District of Columbia, pre-July 1993 conservation costs receive rate base treatment. Conservation expenditures for the period July 1993 to December 1994 are recovered through a surcharge mechanism which initially became effective July 11, 1995, and which is scheduled to be updated annually on June 1 to recover 1995 and subsequent conservation expenditures, including a capital cost recovery factor (CCRF) to enable the Company to earn a return on unamortized Demand Side Management (DSM) costs not in rate base. A procedure has been established to consider lost revenue without the need for base rate proceedings. In Maryland, conservation costs are recovered through a surcharge rate which reflects amortization of program costs including costs in the year during which the surcharge commences, a CCRF, 35 incentives, applicable taxes and estimated lost revenue. The Maryland surcharge is established annually in a collaborative process with the recovery of lost revenue subject to a quarterly earnings test. 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, except that assets held for disposal are carried at estimated fair value less estimated costs to sell. Depreciation is recorded on a straight line basis over the equipment's estimated useful life. No depreciation is taken on assets held for disposal. 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 1997, 1996 and 1995. Conservation - ------------ In general, the Company accounts for conservation expenditures in connection with its DSM program as a deferred charge, and amortizes the costs over five years in Maryland and 10 years in the District of Columbia. Unamortized conservation costs totaled 36 $82 million in Maryland and $140 million in the District of Columbia at December 31, 1997, and $96 million in Maryland and $138 million in the District of Columbia at December 31, 1996. 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 7.6% in 1997, 7.4% in 1996 and 7.9% in 1995, compounded semiannually. In Maryland, the Company accrues a CCRF on the retail jurisdictional portion of certain pollution control expenditures related to compliance with the Clean Air Act (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, the Company's nonutility subsidiary, 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. 37 New Accounting Standards - ------------------------ Effective December 31, 1997, the Company adopted SFAS No. 128 entitled "Earnings per Share" which was issued by the Financial Accounting Standards Board (FASB) in February 1997. Although SFAS No. 128 replaces the presentation of primary earnings per share (EPS) with a presentation of basic EPS, it had no impact on the calculation of the Company's EPS. SFAS No. 128 also requires dual presentation of basic and diluted EPS on the face of the statement of earnings and requires a reconciliation of the numerator and denominator used in the basic and fully diluted EPS computations. See the Notes to Consolidated Financial Statements, (7) Common Equity. SFAS No. 129 entitled "Disclosure of Information about Capital Structure", issued by the FASB in February 1997, is also effective for calendar year 1997 financial statements. SFAS No. 129 consolidates disclosures required by several existing pronouncements. The Company's disclosures are already in compliance with such pronouncements and, accordingly, SFAS No. 129 does not require any change to existing disclosures. In June 1997, the FASB issued SFAS No. 130 entitled "Reporting Comprehensive Income" which became effective January 1, 1998. SFAS No. 130 establishes standards for reporting and display of comprehensive income and its components. All items that are required to be recognized under accounting standards as components of comprehensive income must be reported in a financial statement that is displayed with the same prominence as other financial statements. The Company's principal components of comprehensive income are net income, and unrealized gains and losses on marketable securities. In June 1997, the FASB also issued SFAS No. 131 entitled "Disclosures about Segments of an Enterprise and Related Information" which will become effective for the Company's 1998 calendar year financial statements and will impact quarterly reporting beginning in the first quarter of 1999. The Company does not expect adoption of this pronouncement to have a significant impact on its reporting and disclosure requirements. 38 (2) Total Revenue ------------- The Company's retail service area includes all of the District of Columbia and major portions of Montgomery and Prince George's counties in suburban Maryland. The Company supplies electricity, at wholesale, under a contract with Southern Maryland Electric Cooperative, Inc. (SMECO), and also delivers economy energy to the Pennsylvania-New Jersey-Maryland Interconnection Association (PJM) of which the Company is a member. PJM is composed of more than 80 electric utilities, independent power producers, power marketers, cooperatives and municipals which operate on a fully integrated basis. Total revenue for each year was comprised as shown below. - ----------------------------------------------------------------- 1997 1996 1995 -------------------------------------------------- Amount % Amount % Amount % - ----------------------------------------------------------------- (Thousands of Dollars) Sales of Electricity Residential $ 524,695 29.2 $ 548,108 30.1 $ 543,532 30.0 Commercial 851,375 47.3 852,497 46.7 848,892 46.8 U.S. Government 249,341 13.9 250,422 13.7 252,144 13.9 D.C. Government 51,089 2.8 51,565 2.8 52,105 2.9 Wholesale 123,300 6.8 122,149 6.7 117,117 6.4 ---------- ----- --------- ----- ---------- ----- Total 1,799,800 100.0 1,824,741 100.0 1,813,790 100.0 ===== ===== ===== Other electric revenue 11,029 10,116 8,642 ---------- ---------- ---------- Operating revenue 1,810,829 1,834,857 1,822,432 Interchange deliveries 52,681 175,454 53,670 ---------- ---------- ---------- Total Revenue $1,863,510 $2,010,311 $1,876,102 ========== ========== ========== - ----------------------------------------------------------------- Sales of electricity include base rate revenue and fuel rate revenue. Fuel rate revenue was $509.1 million in 1997, $521.9 million in 1996 and $526.6 million in 1995. 39 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 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 Company reduced its Maryland fuel rate by 9.5% effective August 28, 1997. Included in the reduction was an adjustment for a deferred fuel amortization charge to refund over a twelve month period approximately $20.7 million of previously overrecovered fuel costs incurred through June 30, 1997. The Maryland Commission order approving the reduction became final on December 13, 1997. 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. Rates for service, at wholesale, to SMECO include a fuel adjustment charge based upon estimated applicable fuel and net interchange costs for each billing month. The difference between the estimated costs and the actual applicable fuel and net interchange costs incurred each month is reflected as an adjustment to the fuel rate in the succeeding month. Interchange deliveries include power sales tariff transactions, predominantly those where the Company buys energy from one party for the purpose of selling that energy to a third party. The benefits derived from interchange deliveries are 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 its subsidiary. 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. 40 Pension expense included in net income was $11.6 million in 1997, $14.2 million in 1996 and $13.9 million in 1995. The net periodic pension cost was computed as follows. - ----------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------- (Thousands of Dollars) Service cost-benefits earned $11,400 $11,400 $ 9,900 Interest cost on projected benefit obligation 32,400 30,600 28,400 Actual return on Program assets (64,900) (38,200) (51,900) Differences between actual and expected return on Program assets and net amortization 32,700 10,400 27,500 ------- ------- ------- Pension cost $11,600 $14,200 $13,900 ======= ======= ======= - ---------------------------------------------------------------- 41 Program assets are stated at fair value and were comprised of approximately 47% and 53% of cash equivalents and fixed income investments and the balance in equity investments at December 31, 1997 and 1996, respectively. The following table sets forth the Program's funded status and amounts included in Other Deferred Charges on the Consolidated Balance Sheets. - ----------------------------------------------------------------- 1997 1996 - ----------------------------------------------------------------- (Thousands of Dollars) Actuarial present value of benefit obligations: Program benefits: Vested benefits $(364,200) $(322,000) Nonvested benefits (49,300) (49,400) --------- --------- Accumulated benefit obligation $(413,500) $(371,400) ========= ========= Actuarial present value of projected benefit obligation $(495,600) $(438,100) Program assets at fair value 468,800 402,500 --------- --------- Projected benefit obligation in excess of Program assets (26,800) (35,600) Unrecognized actuarial loss 77,400 68,700 Unrecognized prior service cost 13,500 14,900 Unrecognized net obligation at January 1, 1987, being recognized over 18 years 300 300 --------- --------- Prepaid pension expense $ 64,400 $ 48,300 ========= ========= - ----------------------------------------------------------------- Measurement of the actuarial present value of the projected benefit obligation was based on assumed weighted average discount rates of 7% and 7.5%, in 1997 and 1996, respectively. The weighted average rate of increase in future compensation levels was 4% in 1997 and 1996. The assumed long-term rate of return on Program assets was 9% in 1997 and 1996. 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 $6 million in 1997, 1996 and 1995. 42 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. Postretirement benefit expense included in net income was $11.1 million, $10.9 million and $9 million in 1997, 1996 and 1995, respectively. The following table sets forth the components of the postretirement expense. - ----------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------- (Thousands of Dollars) Service cost-benefits attributable to service during the year $ 3,600 $ 2,800 $ 2,300 Interest cost on accumulated postretirement benefit obligation 5,300 5,300 4,500 Actual loss (return) on plan assets (2,300) (1,300) (1,900) Amortization of transition obligation 2,100 2,100 2,100 Difference between actual and expected return on plan assets and net amortization 2,400 2,000 2,000 ------- ------- ------- Net postretirement benefit cost $11,100 $10,900 $ 9,000 ======= ======= ======= - ----------------------------------------------------------------- 43 The following table sets forth the accumulated post-retirement benefit obligation reconciled to the amounts recognized on the Consolidated Balance Sheets. - ----------------------------------------------------------------- 1997 1996 - ----------------------------------------------------------------- (Thousands of Dollars) Accumulated postretirement benefit obligation to Retirees and dependents $(44,000) $(44,100) Active employees fully eligible (8,800) (7,900) Active employees not fully eligible (29,200) (21,100) -------- -------- Total accumulated postretirement benefit obligation (82,000) (73,100) Plan assets at fair value 13,600 9,800 -------- -------- Accumulated postretirement benefit obligation in excess of plan assets (68,400) (63,300) Unrecognized transition obligation 31,600 33,700 Unrecognized actuarial loss 36,700 30,800 -------- -------- Prepaid (Accrued) postretirement benefit cost $ (100) $ 1,200 ======== ======== - ----------------------------------------------------------------- The Company's obligation at December 31, 1997 and 1996, was based on a discount rate of 7% and 7.5%, respectively, and a weighted average rate of increase in future compensation levels of 4%. The assumed health-care cost trend rate is 7.0% which declines to 5.5% after a three-year period. A one percentage point increase in the health-care cost trend rate would increase the Accumulated Postretirement Benefit Obligation by $4 million to approximately $86 million and the sum of the service cost and interest cost for 1997 by approximately $.7 million. In January 1997 and 1996, the Company funded the 1997 and 1996 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 1998, the 1998 portion of the Company's estimated liability will be funded. Assets were comprised of cash equivalents, fixed income investments and equity investments and the assumed return on plan assets was 9% in 1997 and 1996. 44 (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 - --------------------------- - ----------------------------------------------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------------------------------------------- (Thousands of Dollars) Utility current tax expense Federal $ 32,252 $ 47,235 $ 68,492 State and local 4,691 6,281 9,173 ----------- --------- --------- Total utility current tax expense 36,943 53,516 77,665 ----------- --------- --------- Utility deferred tax expense Federal 56,278 74,762 48,339 State and local 7,916 10,383 7,084 Investment tax credits (3,650) (3,649) (3,649) ----------- --------- --------- Total utility deferred tax expense 60,544 81,496 51,774 ----------- --------- --------- Total utility income tax expense 97,487 135,012 129,439 ----------- --------- --------- Nonutility subsidiary current tax expense Federal 30,421 (18,252) (35,592) Nonutility subsidiary deferred tax expense Federal (62,271) (36,373) (50,116) ----------- --------- --------- Total nonutility subsidiary income tax expense (credit) (31,850) (54,625) (85,708) ----------- --------- --------- Total consolidated income tax expense 65,637 80,387 43,731 Income taxes included in other income (52,094) (53,698) (84,729) ----------- --------- --------- Income taxes included in utility operating expenses $ 117,731 $ 134,085 $ 128,460 =========== ========= ========= 45
Reconciliation of Consolidated Income Tax Expense - ------------------------------------------------- - ----------------------------------------------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------------------------------------------- (Thousands of Dollars) Income before income taxes $ 247,500 $ 317,347 $ 138,122 =========== ========= ========= Utility income tax at federal statutory rate $ 91,783 $ 124,277 $ 121,879 Increases (decreases) resulting from Depreciation 10,853 9,867 9,173 Removal costs (5,902) (3,574) (7,204) Allowance for funds used during construction 859 691 595 Other (4,432) (3,117) (1,613) State income taxes, net of federal effect 8,194 10,749 10,648 Tax credits (3,868) (3,881) (4,039) ----------- --------- --------- Total utility income tax expense 97,487 135,012 129,439 ----------- --------- --------- Nonutility subsidiary income tax at federal statutory rate (5,169) (13,206) (73,537) Increases (decreases) resulting from Dividends received deduction (5,419) (7,114) (8,524) Reversal of previously accrued deferred taxes (10,125) (30,804) - Other (11,137) (3,501) (3,647) ----------- --------- --------- Total nonutility subsidiary income tax expense (credit) (31,850) (54,625) (85,708) ----------- --------- --------- Total consolidated income tax expense 65,637 80,387 43,731 Income taxes included in other income (52,094) (53,698) (84,729) ----------- --------- --------- Income taxes included in utility operating expenses $ 117,731 $ 134,085 $ 128,460 =========== ========= =========
Components of Consolidated Deferred Tax Liabilities (Assets) - ------------------------------------------------------------ At December 31, ------------------------ 1997 1996 ------------------------ (Thousands of Dollars) Utility deferred tax liabilities (assets) Depreciation and other book to tax basis differences $ 869,343 $ 821,656 Rapid amortization of certified pollution control facilities 25,445 24,816 Deferred taxes on amounts to be collected through future rates 90,154 90,284 Property taxes 13,525 12,664 Deferred fuel (7,369) (14,663) Prepayment premium on debt retirement 19,962 21,025 Deferred investment tax credit (21,697) (23,079) Contributions in aid of construction (30,054) (28,719) Contributions to pension plan 18,157 16,170 Conservation costs (demand side management) 48,041 41,106 Other 21,683 21,653 ----------- --------- Total utility deferred tax liabilities (net) 1,047,190 982,913 Current portion of utility deferred tax liabilities (included in Other Current Liabilities) 17,872 9,271 ----------- --------- Total utility deferred tax liabilities (net) - noncurrent $ 1,029,318 $ 973,642 =========== ========= Nonutility subsidiary deferred tax liabilities (assets) Finance leases $ 119,448 $ 144,667 Operating leases 28,823 57,006 Reversal of previously accrued taxes related to partnerships (5,215) (7,455) Alternative minimum tax (97,109) (97,109) Other (45,732) (36,041) ----------- --------- Total nonutility subsidiary deferred tax liabilities (net), (included in Deferred taxes and other) $ 215 $ 61,068 =========== ========= 46
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, 1997 and 1996. 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 its subsidiary file a consolidated federal income tax return. The Company's federal income tax liabilities for all years through 1993 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. (5) Other Taxes ----------- Taxes, other than income taxes, charged to utility operating expenses for each period are shown below. - ----------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------- (Thousands of Dollars) Gross receipts $ 95,753 $ 96,147 $ 95,158 Property 71,438 69,234 64,991 Payroll 10,469 10,673 11,269 County fuel-energy 15,448 15,448 21,887 Environmental, use and other 8,612 8,863 9,403 -------- -------- -------- $201,720 $200,365 $202,708 ======== ======== ======== - ----------------------------------------------------------------- 47 (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 $89.9 million at December 31, 1997, and $88.7 million at December 31, 1996, includes $.3 million and $.7 million of Construction Work in Progress, respectively. 48 (7) Common Equity Changes in common stock, premium on stock and retained income are summarized below.
- --------------------------------------------------------------------------------------- Common Stock Premium Retained Shares Par Value on Stock Income - --------------------------------------------------------------------------------------- (Thousands of Dollars) Balance, December 31, 1994 118,248,103 118,248 1,020,689 830,524 Net income before net loss from nonutility subsidiary - - - 218,788 Nonutility subsidiary: Net loss - - - (124,397) Marketable securities net unrealized gain, net of tax - - - 30,701 Dividends: Preferred stock - - - (16,851) Common stock - - - (196,469) Conversion of preferred stock 9,730 10 74 - Gain on acquisition of preferred stock - - 5 - Other capital reductions - - (23) - Sale of common stock through Shareholder Dividend Reinvestment Plan 158,501 159 2,881 - Issuance of common stock to Employee Savings Plans 78,243 78 1,462 - ----------- ---------- ----------- ---------- Balance, December 31, 1995 118,494,577 118,495 1,025,088 742,296 Net income before net earnings from nonutility subsidiary - - - 220,066 Nonutility subsidiary: Net earnings - - - 16,894 Marketable securities net unrealized loss, net of tax - - - (5,755) Dividends: Preferred stock - - - (16,604) Common stock - - - (196,612) Conversion of preferred stock 3,239 3 25 - Conversion of debentures 2,221 2 58 - Other capital contributions - - 16 - ----------- ---------- ----------- ---------- Balance, December 31, 1996 118,500,037 118,500 1,025,187 760,285 Net income before net earnings from nonutility subsidiary - - - 164,749 Nonutility subsidiary: Net earnings - - - 17,081 Marketable securities net unrealized gain, net of tax - - - 5,397 Dividends: Preferred stock - - - (16,579) Common stock - - - (196,615) Conversion of preferred stock 854 1 6 - Other capital contributions - - (26) - ----------- ---------- ----------- ---------- Balance, December 31, 1997 118,500,891 $ 118,501 $ 1,025,167 $ 734,318 =========== ========== =========== ========== 49
Reconciliations of the numerator and denominator for earnings per common share and fully diluted earnings per common share are shown below.
------------- --------------- --------- Income Shares Per Share (Numerator) (Denominator) Amount ------------ -------------- --------- (Thousands except Per Share Data) 1995 Earnings Per Share Reconciliation: Net income $94,391 Preferred dividends (16,851) ------------ -------------- --------- Earnings per common share $77,540 118,412 $0.65 Convertible debentures - - Convertible preferred stock 16 38 ------------ -------------- --------- Fully diluted earnings per common share $77,556 118,450 $0.65 ============ ============== ========= 1996 Earnings Per Share Reconciliation: Net income $236,960 Preferred dividends (16,604) ------------ -------------- --------- Earnings per common share $220,356 118,497 $1.86 Convertible debentures 6,416 5,811 Convertible preferred stock 15 35 ------------ -------------- --------- Fully diluted earnings per common share $226,787 124,343 $1.82 ============ ============== ========= 1997 Earnings Per Share Reconciliation: Net income $181,830 Preferred dividends (16,579) ------------ -------------- --------- Earnings per common share $165,251 118,500 $1.39 Convertible debentures 6,353 5,757 Convertible preferred stock 14 34 ------------ -------------- --------- Fully diluted earnings per common share $171,618 124,291 $1.38 ============ ============== ========= These amounts are not reflected in the computation of diluted EPS because the effects are antidilutive and would increase diluted EPS. 50
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, 1997, 35,046 shares of common stock were reserved for issuance upon the conversion of convertible preferred stock, 2,769,412 and 3,392,500 shares were reserved for 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, 1997. 51 (8) Serial Preferred Stock ---------------------- The Company has authorized 11,095,501 shares of cumulative $50 par value Serial Preferred Stock. At December 31, 1997 and 1996, there were outstanding 5,345,499 shares and 5,375,646 shares, respectively. The various series of Serial Preferred Stock outstanding [excluding 2,839,696 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 1997 1996 - ----------------------------------------------------------------- (Thousands of Dollars) $2.44 Series of 1957, 300,000 shares $51.00 $ 15,000 $ 15,000 $2.46 Series of 1958, 300,000 shares $51.00 15,000 15,000 $2.28 Series of 1965, 400,000 shares $51.00 20,000 20,000 $3.82 Series of 1969, 500,000 shares $51.00 25,000 25,000 $2.44 Convertible Series of 1966, 5,803 and 5,950 shares, respectively $50.00 290 298 Auction Series A, 1,000,000 shares $50.00 50,000 50,000 -------- -------- $125,290 $125,298 ======== ======== - ----------------------------------------------------------------- The $2.44 Convertible Series of 1966 is convertible into common stock of the Company at a price based upon a formula that is subject to adjustment in certain events. At December 31, 1997, 5.88 shares of common stock could be obtained upon the conversion of each share of convertible preferred stock at the then effective conversion price of $8.51 per share of common stock. The number of shares of this series converted into common stock was 147 shares in 1997, 556 shares in 1996 and 1,676 shares in 1995. 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 4.374% ($2.187) for the period December 1, 1997 through February 28, 1998. The average annual dividend rates were 4.221% ($2.1105) in 1997 and 4.153% ($2.0765) in 1996. 52 (9) Redeemable Serial Preferred Stock --------------------------------- The outstanding series of $50 par value Redeemable Serial Preferred Stock are shown below. - ----------------------------------------------------------------- December 31, 1997 1996 - ----------------------------------------------------------------- (Thousands of Dollars) $3.37 Series of 1987, 839,696 and 869,696 shares $ 41,985 $ 43,485 $3.89 Series of 1991, 1,000,000 shares 50,000 50,000 $3.40 Series of 1992, 1,000,000 shares 50,000 50,000 -------- -------- 141,985 143,485 Redemption Requirement due within one year (985) (985) -------- -------- $141,000 $142,500 ======== ======== - ---------------------------------------------------------------- The shares of the $3.37 (6.74%) Series are subject to mandatory redemption, at par, through the operation of a sinking fund. Beginning June 1993, not less than 30,000 nor more than 60,000 shares will be redeemed annually. The option to redeem in excess of 30,000 shares annually is not cumulative; however, shares which are acquired or redeemed by the Company other than through the operation of the sinking fund may, at the option of the Company, be applied toward the satisfaction of sinking fund requirements. Presently, the shares are callable for redemption at a per share price of $51.13, which is reduced to par value beginning June 1, 2002. The shares of the $3.89 (7.78%) Series are subject to mandatory redemption, at par, through the operation of a sinking fund which will redeem not less than 165,000 nor more than 330,000 shares annually, beginning June 1, 2001, and 175,000 shares on June 1, 2006. The option to redeem in excess of 165,000 shares annually is not cumulative. The shares may be called for redemption at any time at a per share price of $53.89, which is reduced in succeeding years, equaling $50.98 beginning June 1, 2003. 53 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 2002 with respect to the Redeemable Serial Preferred Stock are $1 million in 1998, $1.5 million annually in 1999 and 2000, $9.8 million in 2001 and $12.3 million in 2002. 54 (10) Long-Term Debt
Details of long-term debt are shown below. - ------------------------------------------------------------------------------------------------------ Interest December 31, Rate Maturity 1997 1996 - ------------------------------------------------------------------------------------------------------ (Thousands of Dollars) First Mortgage Bonds Fixed Rate Series: 4-3/8% February 15, 1998 $ 50,000 $ 50,000 4-1/2% May 15, 1999 45,000 45,000 9% April 15, 2000 100,000 100,000 5-1/8% April 1, 2001 15,000 15,000 5-7/8% May 1, 2002 35,000 35,000 6-5/8% February 15, 2003 40,000 40,000 5-5/8% October 15, 2003 50,000 50,000 6-1/2% September 15, 2005 100,000 100,000 6-1/4% October 15, 2007 PUT date October 15, 2004 175,000 - 6-1/2% March 15, 2008 78,000 78,000 5-7/8% October 15, 2008 50,000 50,000 5-3/4% March 15, 2010 16,000 16,000 9% June 1, 2021 100,000 100,000 6% September 1, 2022 30,000 30,000 6-3/8% January 15, 2023 37,000 37,000 7-1/4% July 1, 2023 100,000 100,000 6-7/8% September 1, 2023 100,000 100,000 5-3/8% February 15, 2024 42,500 42,500 5-3/8% February 15, 2024 38,300 38,300 6-7/8% October 15, 2024 75,000 75,000 7-3/8% September 15, 2025 75,000 75,000 8-1/2% May 15, 2027 75,000 75,000 7-1/2% March 15, 2028 40,000 40,000 Variable Rate Series: Adjustable rate December 1, 2001 50,000 50,000 ---------- ---------- Total First Mortgage Bonds 1,516,800 1,341,800 Convertible Debentures 5% September 1, 2002 115,000 115,000 7% January 15, 2018 63,905 65,367 Medium-Term Notes Fixed Rate Series: 6.66% to 6.73% May 1997 - 100,000 9.08% July and August 1997 - 50,000 6.53% December 17, 2001 100,000 100,000 7.46% to 7.60% January 2002 40,000 40,000 7.64% January 17, 2007 35,000 35,000 6.25% January 20, 2009 50,000 50,000 7% January 15, 2024 50,000 50,000 Variable Rate Series: Adjustable rate June 1, 2027 8,090 - ---------- ---------- Total Medium Term Notes 283,090 425,000 ---------- ---------- Total Utility Long-Term Debt 1,978,795 1,947,167 Net unamortized discount (26,240) (28,109) Current portion (51,069) (151,460) ---------- ---------- Net Utility Long-Term Debt $1,901,486 $1,767,598 ========== ========== Nonutility Subsidiary Long-Term Debt Varying rates through 2011 $ 830,458 $ 996,232 ========== ========== 55
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 October 1997, the Company issued $175 million principal amount of 6-1/4% 10 PUT 7-Year First Mortgage Bonds maturing in 2007. Each new bond will be repayable on October 15, 2004, at the option of the holder, at 100% of its principal amount, together with accrued and unpaid interest. The proceeds were used to refund short-term debt incurred to finance ongoing construction and operating activities and to pay at maturity, in July and August 1997, $50 million principal amount of medium-term notes; and to pay at maturity $50 million principal amount of First Mortgage Bonds due February 15, 1998. 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, 1997, the applicable interest rate is 7.38%. The applicable interest rate was 7.867% at December 1, 1996, and 7.443% at December 1, 1995. 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, 1997, are $50 million in 1998, $45 million in 1999, $100 million in 2000, $165 million in 2001 and $190 million in 2002. Nonutility Subsidiary Long-Term Debt - ------------------------------------ Long-term debt at December 31, 1997, consisted of $778.3 million of recourse debt from institutional lenders maturing at various dates between 1998 and 2003. The interest rates of such borrowings ranged from 5% to 10.1%. The weighted average interest rate was 7.48% at December 31, 1997, 7.44% at December 31, 1996, and 7.66% at December 31, 1995. Annual aggregate principal repayments are $300.8 million in 1998, $170 million in 1999, $122.5 million in 2000, $71.5 million in 2001 and $93 million in 2002. 56 Long-term debt also includes $52.2 million of non-recourse debt, $29.4 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% and LIBOR plus 1.375% with final maturity on March 15, 2002. Non-recourse debt of $22.8 million is related to PCI's majority-owned real estate partnerships of which $15.1 million is due in consecutive monthly installments with maturity on May 11, 2001, based on a 30-year amortization period at a fixed rate of interest of 9.05%. The remaining non-recourse real estate debt consists of $7.7 million payable in monthly installments at a fixed rate of interest of 9.66% with final maturity on October 1, 2011. 57 (11) Fair Value of Financial Instruments - ---------------------------------------- The estimated fair values of the Company's financial instruments at December 31, 1997, and 1996 are shown below.
- ------------------------------------------------------------------------------------------------ December 31, 1997 1996 - ------------------------------------------------------------------------------------------------ Carrying Fair Carrying Fair Amount Value Amount Value ----------- ----------- ----------- ----------- (Thousands of Dollars) Utility Capitalization and Liabilities Serial preferred stock $ 125,290 127,251 125,298 113,285 Redeemable serial preferred stock $ 141,000 142,612 142,500 146,491 Long-term debt First mortgage bonds $1,452,420 1,507,515 1,327,389 1,319,976 Medium-term notes $ 281,155 289,950 272,788 274,242 Convertible debentures $ 167,911 172,400 167,421 171,880 Nonutility Subsidiary Assets Marketable securities $ 302,522 302,522 377,237 377,237 Notes receivable $ 23,125 19,549 72,251 71,593 Liabilities Long-term debt $ 830,458 840,974 996,232 1,011,814 - ------------------------------------------------------------------------------------------------ 58
The methods and assumptions below were used to estimate, at December 31, 1997 and 1996, 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, including Redeemable Serial Preferred Stock, 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 5.3% to 6.3%. The Company maintains a minimum 100% line of credit back-up, in the amount of $180 million, for its outstanding commercial promissory notes, which was unused during 1997, 1996 and 1995. 59 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 1997, 1996 and 1995. (13) Commitments and Contingencies ----------------------------- Termination of Proposed Merger - ------------------------------ On December 22, 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. At December 31, 1996, deferred costs related to the Merger totaled $29 million and are included in "Other Deferred Charges" on the Consolidated Balance Sheet. 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 six 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 $17.1 million in 1997, $16.2 million in 1996 and $15.6 million in 1995. The approximate annual commitments under all operating leases, reduced by rentals to be received under subleases are $13.3 million in 1998, $7.7 million in 1999, $5.7 million in 2000, $4.3 million in 2001, $1.1 million in 2002 and a total of $5.1 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. 60 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 $21 million and $14 million at December 31, 1997 and 1996, respectively. Fuel Contracts - -------------- The Company has numerous longer-term coal contracts, expiring primarily in the period ranging from late-1998 to mid-1999, for aggregate annual deliveries of approximately 3.2 million tons. Deliveries under these contracts are expected to provide approximately 48% of the estimated system coal requirements in 1998. The Company will purchase the balance of its coal requirements under shorter-term agreements and on a spot basis from a variety of suppliers. Prices under the Company's 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. Capacity Purchase Agreements - ---------------------------- The Company's long-term capacity purchase agreements with Ohio Edison and Allegheny Energy, Inc. (AEI, formerly Allegheny Power System) commenced June 1, 1987, and are expected to continue at the 450 megawatt level through 2005. Under the terms of the agreements with Ohio Edison and AEI, the Company is required to make capacity payments, subject to certain contingencies, which include a share of Ohio Edison's fixed operating and maintenance cost. The Company also has a 25-year agreement with Panda Brandywine, L.P. (Panda) for 230 megawatts of capacity supplied by a gas-fueled combined-cycle cogenerator, which achieved full commercial operation in October 1996. The Company began purchasing energy from the Panda facility in August 1996 and capacity payments under this agreement commenced in January 1997. In November 1997, the Company agreed to purchase 32 megawatts of capacity from the Montgomery County Resource Recovery Facility for the period November 1, 1997 to December 31, 1998. This purchase facilitated the sale of 35 megawatts of capacity to Northeast Utilities Service Company. The capacity commitments under these agreements, including a share of Ohio Edison's fixed 61 operating and maintenance cost, are estimated at $143 million for 1998, $198 million for 1999, $201 million for 2000, $207 million for 2001 and 2002 and $1.4 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 complete. 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 $8 million and $7 million at December 31, 1997 and 1996, 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 October 6, 1997, the Company received notice from the U.S. Environmental Protection Agency (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. 62 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 October 1994, a Remedial Investigation/Feasibility Study (RI/FS) report was submitted to the EPA with respect to a site in Philadelphia, Pennsylvania. Pursuant to an agreement among the PRPs, the Company is responsible for 12% of the costs of the RI/FS. Total costs of the RI/FS and associated activities prior to the issuance of a ROD by the EPA, including legal fees, are currently estimated to be $7.5 million. The Company has paid $.9 million as of December 31, 1997. The report included a number of possible remedies, the estimated costs of which range from $2 million to $90 million. In July 1995, the EPA announced its proposed remedial action plan for the site and indicated it will accept comments on the plan from any interested parties. The EPA's estimate of the costs associated with implementation of the plan is approximately $17 million. The Company cannot predict whether the EPA will include the plan in its ROD as proposed or make changes as a result of comments received. In addition, the Company cannot estimate the total extent of the EPA's administrative and oversight costs. To date, the Company has accrued $1.7 million for its share of this contingency. 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 63 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 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 50 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, 1997, 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 fiscal 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. 64 Labor Agreement - --------------- In January 1998, the Company's current 1993 Labor Agreement with Local 1900 of the International Brotherhood of Electrical Workers (IBEW) was extended until June 1, 1999. This extension provides for a 2.5% lump-sum payment to all members of Local 1900 upon ratification of the agreement by the union. All other provisions of the 1993 agreement remain the same. (14) Supplemental Disclosure of Cash Flow Information ------------------------------------------------ Listed below is supplemental disclosure of cash flow information. - ----------------------------------------------------------------- 1997 1996 1995 - ----------------------------------------------------------------- (Thousands of Dollars) Cash paid for: Interest, net of capitalized interest (including nonutility subsidiary interest of $71,492, $83,389 and $93,672) $202,754 $216,967 $223,789 Income taxes $ 12,475 $ 28,555 $ 44,725 - ----------------------------------------------------------------- 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. 65 (15) Selected Nonutility Subsidiary Financial Information ---------------------------------------------------- Selected financial information of the Company's consolidated, wholly owned nonutility investment subsidiary, Potomac Capital Investment Corporation (PCI) and its subsidiaries, is presented below. Subsidiary equity at December 31, 1997, and December 31, 1996, was $227 million and $196.3 million, respectively. These amounts include $6.5 million and $1.1 million of unrealized appreciation, at December 31, 1997 and 1996, respectively, relating to the marketable securities portfolio on an after-tax basis. - ----------------------------------------------------------------- For the year ended December 31, 1997 1996 1995 - ----------------------------------------------------------------- (Thousands of Dollars) Income Leasing activities $ 75,584 $ 91,661 $ 100,640 Marketable securities 28,641 33,690 36,121 Other 20,915 (10,385) (2,268) -------- --------- -------- 125,140 114,966 134,493 -------- --------- -------- Expenses Interest 68,959 83,442 91,637 Administrative and general 13,489 15,529 10,479 Depreciation and operating 55,439 40,982 72,404 Loss on assets held for disposal 2,022 12,744 170,078 Income tax credit (31,850) (54,625) (85,708) -------- --------- --------- 108,059 98,072 258,890 -------- --------- --------- Net earnings (loss) from nonutility subsidiary $ 17,081 $ 16,894 $(124,397) ======== ========= ========= 66 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 (losses) on marketable securities, which relate primarily to mandatory redeemable preferred stock, are shown below: December 31, December 31, 1997 1996 ------------ ------------ (Thousands of Dollars) Market value $302,522 $ 377,237 Cost 292,580 375,598 --------- --------- Net unrealized gain $ 9,942 $ 1,639 ========= ========= Included in net unrealized gains and losses are 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 $7.5 million and $4.7 million for 1997 and 1996, respectively. Gross realized losses were $.6 million and $1.1 million for 1997 and 1996, respectively. At December 31, 1997, the contractual maturities for mandatory redeemable preferred stock are $4.7 million within one year, $118.8 million from one to five years, $81.4 million from five to 10 years and $87.7 million for over 10 years. 67 Leasing Activities - ------------------ PCI's net investment in finance leases is summarized below. - ----------------------------------------------------------------- December 31, 1997 1996 - ----------------------------------------------------------------- (Thousands of Dollars) Rents receivable $664,211 $711,961 Estimated residual values 87,965 102,590 Less: Unearned and deferred income (288,584) (329,579) -------- -------- Investment in finance leases 463,592 484,972 Less: Deferred taxes arising from finance leases (119,448) (144,667) -------- -------- Net investment in finance leases $344,144 $340,305 ======== ======== - ----------------------------------------------------------------- Minimum lease payments receivable from finance leases of aircraft and generating facilities for each of the years 1998 through 2002 are $33 million, $34.5 million, $37.3 million, $36.7 million, and $34.9 million, respectively. Net income from leveraged leases was $16.4 million in 1997, $22.5 million in 1996 and $11 million in 1995. Rent payments receivable from aircraft equipment operating leases for each of the years 1998 through 2002 are $37 million in 1998, $35.5 million in 1999, $30 million in 2000, $22.5 million in 2001 and $3.5 million in 2002. 68 (16) Quarterly Financial Summary (Unaudited)
- --------------------------------------------------------------------------------------------------------------------- 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter Total - --------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars except Per Share Data) 1997 Operating Revenue $ 374,486 439,555 618,218 378,570 1,810,829 Total Revenue $ 389,060 450,971 633,042 390,437 1,863,510 Operating Expenses $ 346,838 370,351 466,542 354,396 1,538,127 Operating Income $ 42,222 80,620 166,500 36,041 325,383 Net Income (Loss) $ 22,982 50,124 135,985 (27,261) 181,830 Earnings (Loss) for Common Stock $ 18,837 45,987 131,828 (31,401) 165,251 Earnings (Loss) per Common Share $ .16 .39 1.11 (.27) 1.39 Fully 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 $ 385,272 462,705 614,357 372,523 1,834,857 Total Revenue $ 436,593 501,780 658,225 413,713 2,010,311 Operating Expenses $ 392,566 406,437 491,963 370,906 1,661,872 Operating Income $ 44,027 95,343 166,262 42,807 348,439 Net Income $ 14,734 72,253 138,687 11,286 236,960 Earnings for Common Stock $ 10,574 68,116 134,536 7,130 220,356 Earnings per Common Share $ .09 .57 1.14 .06 1.86 Fully Diluted Earnings per Common Share $ .09 .56 1.09 .06 1.82 Dividends per Share $ .415 .415 .415 .415 1.66 1995 Operating Revenue $ 363,433 440,455 642,511 376,033 1,822,432 Total Revenue $ 364,909 445,359 663,584 402,250 1,876,102 Operating Expenses $ 334,091 354,120 480,348 359,802 1,528,361 Operating Income $ 30,818 91,239 183,236 42,448 347,741 Net (Loss) Income $ (3,972) (56,838) 145,947 9,254 94,391 (Loss) Earnings for Common Stock $ (8,213) (61,072) 141,747 5,078 77,540 (Loss) Earnings per Common Share $ (.07) (.52) 1.20 .04 .65 Fully Diluted (Loss) Earnings per Common Share $ (.07) (.52) 1.15 .04 .65 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 earnings per share and fully diluted earnings per share may not equal the earnings per share and fully diluted earnings per share for the year due to changes in the number of common shares outstanding during the year and, with respect to the fully diluted earnings per share, changes in the amount of dilutive securities. 69
Stock Market Information
- ------------------------------------------------------------------------------------------------------------------------------------ 1997 High Low 1996 High Low - ------------------------------------------------------------------------------------------------------------------------------------ 1st Quarter $26 $23-7/8 1st Quarter $27-3/8 $24-1/2 2nd Quarter $24-7/8 $21-1/8 2nd Quarter $26-5/8 $24-3/8 3rd Quarter $23-3/4 $21 3rd Quarter $26-3/4 $24 4th Quarter $26 $21 4th Quarter $27-3/8 $23-5/8 (Close $25-13/16) (Close $25-3/4) Shareholders at December 31, 1997: 81,229 - ------------------------------------------------------------------------------------------------------------------------------------
Selected Consolidated Financial Data
- ------------------------------------------------------------------------------------------------------------------------------------ 1997 1996 1995 1994 1993 1992 1987 - ------------------------------------------------------------------------------------------------------------------------------------ (Thousands except Per Share Data) Operating Revenue $1,810,829 1,834,857 1,822,432 1,790,600 1,702,442 1,562,167 1,332,109 Total Revenue $1,863,510 2,010,311 1,876,102 1,823,074 1,725,205 1,601,558 1,384,239 Operating Expenses $1,538,127 1,661,872 1,528,361 1,498,581 1,400,543 1,322,105 1,122,083 Net Earnings (Loss) from Nonutility Subsidiary $ 17,081 16,894 (124,397) 19,088 25,101 28,161 32,150 Income Before Cumulative Effect of Accounting change $ 181,830 236,960 94,391 227,162 241,579 200,760 208,222 Cumulative Effect of Accounting Change, Net of Income Taxes $ - - - - - 16,022 - Net Income $ 181,830 236,960 94,391 227,162 241,579 216,782 208,222 Earnings for Common Stock $ 165,251 220,356 77,540 210,725 225,324 202,390 199,175 Average Common Shares Outstanding 118,500 118,497 118,412 118,006 115,640 112,390 94,438 Earnings (Loss) Per Common Share Utility Operations $ 1.25 1.72 1.70 1.63 1.73 1.55 1.77 Nonutility Subsidiary $ 0.14 .14 (1.05) .16 .22 .25 .34 Consolidated $ 1.39 1.86 .65 1.79 1.95 1.80 2.11 Fully Diluted Earnings (Loss) Per Common Share Utility Operations $ 1.24 1.69 1.70 1.60 1.70 1.54 1.77 Nonutility Subsidiary $ 0.14 .13 (1.05) .15 .21 .24 .34 Consolidated $ 1.38 1.82 .65 1.75 1.91 1.78 2.11 Cash Dividends Per Common Share $ 1.66 1.66 1.66 1.66 1.64 1.60 1.30 Investment in Property and Plant $6,514,114 6,321,591 6,161,103 5,974,170 5,701,550 5,404,265 3,699,957 Net Investment in Property and Plant $4,486,334 4,423,249 4,400,311 4,334,399 4,167,551 3,967,898 2,678,921 Utility Assets $5,540,232 5,526,266 5,503,087 5,327,606 5,036,737 4,515,403 3,111,280 Nonutility Subsidiary Assets $1,167,325 1,365,620 1,615,063 1,674,289 1,665,132 1,663,508 598,688 Total Assets $6,707,557 6,891,886 7,118,150 7,001,895 6,701,869 6,178,911 3,709,968 Long-Term Utility Obligations (including redeemable preferred stock) $2,042,486 1,910,098 1,960,562 1,866,962 1,736,621 1,727,609 1,171,925 - ------------------------------------------------------------------------------------------------------------------------------------ Includes $.14 as the cumulative effect of an accounting change for unbilled revenue. Includes ($.28) as the net effect of the write-off of Merger costs. 70
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