-----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, NJusArRCLB3SXggxazOj6hOlw4ckn38akkp0iqvQnBR+Zcq5Q4/PgeF1OtqsbiNg 4MxtmUWXpycxU/UeIHbuYw== 0000079732-96-000014.txt : 19960207 0000079732-96-000014.hdr.sgml : 19960207 ACCESSION NUMBER: 0000079732-96-000014 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19960206 ITEM INFORMATION: Financial statements and exhibits FILED AS OF DATE: 19960206 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: 1934 Act SEC FILE NUMBER: 001-01072 FILM NUMBER: 96511642 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 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) February 6, 1996 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 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. 27.1 Restated Financial Data Schedule....Filed herewith. 99 The 1995 consolidated financial statements of the Company and Subsidiaries, together with the report thereon of Price Waterhouse dated January 19, 1996; 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) By ___________________________ H. Lowell Davis Vice Chairman and Chief Financial Officer February 6, 1996 DATE -3- EX-12 2 COMPUTATION OF RATIOS Item 7 Exhibit 12 Computation of Ratios ---------- --------------------- The computations of the coverage of fixed charges, excluding the cumulative effect of the 1992 accounting change, before income taxes, and the coverage of combined fixed charges and preferred dividends for each of the years 1995 through 1991 on the basis of parent company operations only, are as follows.
For The Year Ended December 31, ------------------------------------------------------- 1995 1994 1993 1992 1991 ------------------------------------------------------- (Thousands of Dollars) Net income before cumulative effect of accounting change $218,788 $208,074 $216,478 $172,599 $186,813 Taxes based on income 129,439 116,648 107,223 76,965 80,988 ------------------------------------------------------- Income before taxes and cumulative effect of accounting change 348,227 324,722 323,701 249,564 267,801 ------------------------------------------------------- Fixed charges: Interest charges 146,558 139,210 141,393 138,097 138,512 Interest factor in rentals 23,431 6,300 5,859 6,140 5,690 ------------------------------------------------------- Total fixed charges 169,989 145,510 147,252 144,237 144,202 ------------------------------------------------------- Income before income taxes, cumulative effect of accounting change and fixed charges $518,216 $470,232 $470,953 $393,801 $412,003 ======== ======== ======== ======== ======== Coverage of fixed charges 3.05 3.23 3.20 2.73 2.86 ==== ==== ==== ==== ==== Preferred dividend requirements $16,851 $16,437 $16,255 $14,392 $12,298 ------------------------------------------------------- Ratio of pre-tax income to net income 1.59 1.56 1.50 1.45 1.43 ------------------------------------------------------- Preferred dividend factor $26,793 $25,642 $24,383 $20,868 $17,586 ------------------------------------------------------- Total fixed charges and preferred dividends $196,782 $171,152 $171,635 $165,105 $161,788 ======== ======== ======== ======== ======== Coverage of combined fixed charges and preferred dividends 2.63 2.75 2.74 2.39 2.55 ==== ==== ==== ==== ====
Item 7 Exhibit 12 Computation of Ratios ---------- --------------------- The computations of the coverage of fixed charges, excluding the cumulative effect of the 1992 accounting change, before income taxes, and the coverage of combined fixed charges and preferred dividends for each of the years 1995 through 1991 on a fully consolidated basis are as follows.
For The Year Ended December 31, ------------------------------------------------------- 1995 1994 1993 1992 1991 ------------------------------------------------------- (Thousands of Dollars) Net income before cumulative effect of accounting change $94,391 $227,162 $241,579 $200,760 $210,164 Taxes based on income 43,731 93,953 62,145 79,481 80,737 ------------------------------------------------------- Income before taxes and cumulative effect of accounting change 138,122 321,115 303,724 280,241 290,901 ------------------------------------------------------- Fixed charges: Interest charges 238,724 224,514 221,312 226,453 225,323 Interest factor in rentals 26,685 9,938 9,257 6,599 6,080 ------------------------------------------------------- Total fixed charges 265,409 234,452 230,569 233,052 231,403 ------------------------------------------------------- Nonutility subsidiary capitalized interest (529) (521) (2,059) (2,200) (6,542) ------------------------------------------------------- Income before income taxes, cumulative effect of accounting change and fixed charges $403,002 $555,046 $532,234 $511,093 $515,762 ======== ======== ======== ======== ======== Coverage of fixed charges 1.52 2.37 2.31 2.19 2.23 ==== ==== ==== ==== ==== Preferred dividend requirements $16,851 $16,437 $16,255 $14,392 $12,298 ------------------------------------------------------- Ratio of pre-tax income to net income 1.46 1.41 1.26 1.40 1.38 ------------------------------------------------------- Preferred dividend factor $24,602 $23,176 $20,481 $20,149 $16,971 ------------------------------------------------------- Total fixed charges and preferred dividends $290,011 $257,628 $251,050 $253,201 $248,374 ======== ======== ======== ======== ======== Coverage of combined fixed charges and preferred dividends 1.39 2.15 2.12 2.02 2.08 ==== ==== ==== ==== ====
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 and 33-61379) of Potomac Electric Power Company and in the Joint Proxy Statement/Prospectus constituting part of the Registration Statement on Form S-4 of Constellation Energy Corporation of our report dated January 19, 1996 appearing on page 30 of Exhibit 99 of the Current Report on Form 8-K of Potomac Electric Power Company dated February 6, 1996. /s/ Price Waterhouse LLP Price Waterhouse LLP Washington, D.C. February 6, 1996 EX-27 4 FINANCIAL DATA SCHEDULE
UT 1 POTOMAC CAPITAL INVESTMENT CORPORATION 1,000 12-MOS DEC-31-1995 JAN-01-1995 DEC-31-1995 PER-BOOK 4,378,269 0 431,204 671,572 1,637,105 7,118,150 118,495 1,010,521 742,296 1,871,312 143,485 125,325 1,817,077 3,540 0 254,925 26,280 0 165,235 20,772 2,690,199 7,118,150 1,876,102 128,460 1,399,901 1,528,361 347,741 (114,300) 233,441 139,050 94,391 16,851 77,540 196,469 127,900 376,722 $.65 0 Included on the Balance Sheet in the caption "Short-term debt." Total annualized interest costs for all utility long-term debt outstanding at December 31, 1995. If all the convertible preferred stock and debentures were converted into common stock, the result would be anti-dilutive.
EX-27 5 FINANCIAL DATA SCHEDULE
UT 1 POTOMAC CAPITAL INVESTMENT CORPORATION 1,000 6-MOS 3-MOS 12-MOS DEC-31-1995 DEC-31-1995 DEC-31-1994 JAN-01-1995 JAN-01-1995 JAN-01-1994 JUN-30-1995 MAR-31-1995 DEC-31-1994 PER-BOOK PER-BOOK PER-BOOK 4,357,551 4,353,341 4,327,434 0 0 0 454,664 372,449 425,138 628,161 588,622 568,069 1,515,821 1,670,401 1,681,254 6,956,197 6,984,813 7,001,895 118,486 118,349 118,248 1,010,593 1,008,180 1,006,526 689,475 785,792 830,524 1,818,554 1,912,321 1,955,298 143,485 143,562 143,563 125,401 125,405 125,409 1,703,370 1,727,848 1,723,399 0 0 0 0 0 0 354,000 237,525 189,600 65,000 40,000 45,445 0 0 0 166,304 166,817 167,324 20,772 20,772 20,772 2,559,311 2,610,563 2,631,085 6,956,197 6,984,813 7,001,895 810,268 364,909 1,823,074 34,394 (421) 119,859 653,817 334,512 1,378,722 688,211 334,091 1,498,581 122,057 30,818 324,493 (113,721) (1,129) 32,257 8,336 29,689 356,750 69,146 33,661 129,588 (60,810) (3,972) 227,162 8,475 4,241 16,437 (69,285) (8,213) 210,725 98,164 49,046 195,755 123,600 123,600 123,700 96,381 60,091 376,450 ($.59) ($.07) $1.79 0 0 0 Included on the Balance Sheet in the caption "Short-term debt." Total annualized interest costs for all utility long-term debt outstanding. If all the convertible preferred stock and debentures were converted into common stock, the result would be anti-dilutive. No material dilution would occur if all the convertible preferred stock and debentures were converted into common stock.
EX-99 6 CONSOLIDATED FINANCIAL STATEMENTS Item 7 Exhibit 99 Financial Information - --------------------- Potomac Electric Power Company and Subsidiaries Contents - -------- Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition...................................... 2 Report of Independent Accountants.......................... 30 Consolidated Statements of Earnings........................ 31 Consolidated Balance Sheets................................ 32 Consolidated Statements of Cash Flows...................... 34 Notes to Consolidated Financial Statements................. 35 Selected Consolidated Financial Data....................... 75 1 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition - ---------------------------------------------------- PROPOSED MERGER - --------------- In September 1995, Potomac Electric Power Company (the Company, PEPCO) announced a proposed merger (the Merger) with Baltimore Gas and Electric Company (BGE). The Merger Agreement was approved by the Board of Directors of each company on September 22, 1995. The Merger requires the approval of shareholders of each company and certain regulatory agencies, including the Federal Energy Regulatory Commission, the Public Service Commissions of Maryland and the District of Columbia and the Nuclear Regulatory Commission. The approval process is expected to take until the end of the first quarter of 1997 to complete. The Company believes that the Merger will provide opportunities to achieve benefits for its shareholders, customers, employees and communities that would not be available to the Company as a separate entity, including expanded opportunities in both the core utility operations and nonutility businesses. Preliminary estimates indicate that the Merger will result in savings of approximately $1.3 billion, net of costs to achieve, over 10 years primarily through economies of scale and eliminating duplicate functions which will result in a reduction in the combined work force of approximately 10%. Sharing of the net savings between customers and shareholders of the Company will be determined in regulatory proceedings. See the Notes to Consolidated Financial Statements, (13) Commitments and Contingencies, for additional information. 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 1995. Fuel and purchased energy, capacity purchase payments and other operating expenses were 53% of total revenue. The Company's principal wholly owned subsidiary, Potomac Capital Investment Corporation (PCI), conducts nonutility investment programs with the objective of supplementing current utility earnings and building long-term shareholder value. The information set forth below discusses the results of operations, capital resources and liquidity during the period 1993 through 1995 for the Company and PCI. 2 The Company's earnings for common stock during 1995 totaled $77.5 million, as compared to $210.7 million in 1994. As set forth below, utility earnings increased from $1.63 in 1994 to $1.70 in 1995. With noncash, non-recurring charges of $1.04 related to the decision to end aircraft equipment leasing investment by PCI, consolidated earnings per share for common stock decreased from $1.79 in 1994 to $.65 for 1995. - ----------------------------------------------------------------- 1995 1994 1993 - ----------------------------------------------------------------- Utility Operations $1.70 $1.63 $1.73 Nonutility Subsidiary (1.05) .16 .22 ----- ----- ----- Consolidated $ .65 $1.79 $1.95 ===== ===== ===== - ----------------------------------------------------------------- The average number of common shares outstanding at December 31, 1995, increased by .4 million shares as compared to December 31, 1994. 3 UTILITY - ------- RESULTS OF OPERATIONS - --------------------- Total Revenue - ------------- The changes in total revenue are shown in the following table. - ----------------------------------------------------------------- Increase (Decrease) from Prior Year 1995 1994 1993 - ----------------------------------------------------------------- (Millions of Dollars) Change in kilowatt-hour sales $ 27.2 $(18.7) $ 87.0 Change in base rate revenue 42.8 32.2 45.4 Change in fuel adjustment clause billings to cover cost of fuel and interchange and capacity purchase payments (39.3) 73.2 8.0 Change in other revenue 1.1 1.5 (.1) ------ ------ ------ Change in Operating Revenue 31.8 88.2 140.3 ------ ------ ------ Change in interchange deliveries 21.2 9.7 (16.7) ------ ------ ------ Change in Total Revenue $ 53.0 $ 97.9 $123.6 ====== ====== ====== - ----------------------------------------------------------------- The $42.8 million change in 1995 base rate revenue compared to 1994 reflects the effects of a District of Columbia rate increase of $27.9 million (effective in July 1995), the continued effect of a 1994 rate increase in the District of Columbia and an increase of $29.2 million associated with the Company's Demand Side Management (DSM) surcharge tariff rate in Maryland, which includes $8.7 million for achieving specified 1994 Maryland energy goals associated with the conservation incentive provision of the tariff. The increase in base rate revenue in 1994 as compared to 1993 reflects the effect of a District of Columbia rate increase of $26.7 million (effective primarily in March 1994) and the continued effect of 1993 rate increases in Maryland. Also, 1994 revenue reflects cooler weather during the summer billing months as compared to the warmer than average weather during the corresponding period in 1993. The Company's base rates in the summer period are higher than at other times of the year, and for 4 many customers incorporate time-of-use rates, to encourage customer conservation and peak load shifting. In addition, 1994 base rate revenue reflects $5 million for achieving specified 1993 Maryland energy goals associated with the conservation incentive provision of the Company's DSM surcharge tariff. The increase in base rate revenue in 1993 as compared to 1992 reflects the effects of Maryland rate increases of $7.3 million (effective June 1993) and $27 million (effective November 1993) and the continued effect of 1992 rate increases in both of the Company's retail jurisdictions. Also, 1993 revenue reflects warmer than average weather during the summer billing months of June through October. An increase in 1995 and 1994 and a decrease in 1993 in revenue from interchange deliveries reflect changes in levels and pricing in energy delivered to the Pennsylvania-New Jersey- Maryland Interconnection Association (PJM). Interchange deliveries in 1995 also reflect an increase in the number of companies involved in power sales tariff interchange transactions, where the Company buys energy from one party for the purpose of selling that energy to a third party. Interchange deliveries continue to be a component of the Company's fuel rates. 5 Kilowatt-hour Sales - ------------------- - ----------------------------------------------------------------- 1995 1994 vs. vs. 1995 1994 1993 1994 1993 - ----------------------------------------------------------------- (Millions of Kilowatt-hours) By Customer Type Residential 6,707 6,574 6,727 2.0% (2.3)% Commercial 11,861 11,685 11,751 1.5 (.6) U.S. Government 3,998 4,010 3,986 (.3) .6 D.C. Government 879 914 903 (3.8) 1.2 Wholesale 2,465 2,363 2,327 4.3 1.5 ------ ------ ------ Total energy sales 25,910 25,546 25,694 1.4 (.6) ====== ====== ====== Interchange Energy deliveries 1,784 800 483 - 65.6 ====== ====== ====== By Geographic Area Maryland, including wholesale 15,594 15,251 15,319 2.2 (.4) District of Columbia 10,316 10,295 10,375 .2 (.8) ------ ------ ------ Total energy sales 25,910 25,546 25,694 1.4 (.6) ====== ====== ====== - ----------------------------------------------------------------- Kilowatt-hour sales increased 1.4% in 1995 resulting in part from a 1% increase in customers. Cooling degree hours and heating degree days remained relatively stable as compared to 1994 but were above the 20-year averages by 4% for cooling degree hours and 5% for heating degree days. Kilowatt-hour sales decreased slightly in 1994 as compared to 1993 as customer usage was down because of 14% fewer cooling degree hours in the summer of 1994. 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. 6 The 1995 summer peak demand of 5,732 megawatts occurred on August 4, 1995. This compares with the 1994 summer peak demand of 5,660 megawatts, and the all-time summer peak demand of 5,769 megawatts which occurred in July 1991. The Company's present generation capability, including capacity purchase contracts, is 6,576 megawatts. In addition, the Company had approximately 270 megawatts available from its dispatchable energy use management programs to meet the 1995 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%, reflecting continuing success with conservation and energy use management programs and anticipated service area growth trends. The 1994-1995 winter season peak demand of 4,685 megawatts was 6.5% 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 - ----------------------------------------------------------------- 1995 1994 1993 - ----------------------------------------------------------------- (Millions of Dollars) Fuel expense $355.4 $392.7 $354.3 ------ ------ ------ Purchased energy PJM receipts 79.4 108.8 108.9 Other purchases 114.2 64.6 64.5 ------ ------ ------ Total purchased energy 193.6 173.4 173.4 ------ ------ ------ Fuel and purchased energy $549.0 $566.1 $527.7 ====== ====== ====== Capacity purchase payments $125.8 $127.8 $ 96.3 ====== ====== ====== - ----------------------------------------------------------------- Net System Generation and Purchased Energy were as follows. - ----------------------------------------------------------------- 1995 1994 1993 - ----------------------------------------------------------------- (Millions of Kilowatt-hours) Net system generation 19,234 19,320 19,145 ====== ====== ====== Purchased energy 9,755 8,356 8,448 ====== ====== ====== - ----------------------------------------------------------------- 7 The 1995 decrease in fuel expense reflects the decrease in the system average fuel cost summarized below and a .4% decrease in net generation. The 1994 increase in fuel expense reflects an increase of .9% in net generation and increased use of major cycling and peaking generation units which burn higher cost fuels. During January 1994, severe cold weather sent demand for electricity to a new winter peak, which required significantly increased net generation. Major cycling and peaking generation units were used to meet the increased demand. The 1993 increase in fuel expense primarily reflects a 4.8% increase in net generation resulting from the increase in kilowatt-hour sales, partially offset by the Company's ability to purchase low-cost economy energy from PJM, which helped keep the fuel expense increase to a minimum. 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) 1995 85.4 6.1 8.5 $1.60 $3.22 $2.10 $1.74 1994 76.1 18.4 5.5 1.73 2.70 2.49 1.95 1993 79.4 17.4 3.2 1.72 2.55 2.88 1.90 - ----------------------------------------------------------------- The 1995 system average unit fuel cost decreased by approximately 11% which was primarily the result of the increased use of lower-cost coal and gas and decreased net generation. The increase of approximately 3% in the 1994 system average unit fuel cost compared with the 1993 system average resulted from increased use of major cycling and peaking generation units which burn higher cost fuels. The Company's major cycling and certain peaking units can burn natural gas or oil, adding flexibility in selecting the most cost-effective fuel mix. The increase in the percent of gas burned in 1995 and 1994 reflects the decreased price of gas and the increased price of oil. The decrease in the actual percent of coal contribution to the fuel mix in 1994 primarily reflects major outages for construction related to Clean Air Act additions on baseload coal-fired generation units. The Company's generating and transmission facilities are interconnected with the other members of PJM and other utilities. The pricing of most PJM internal economy energy transactions is based upon "split savings" so that the price of such energy is 8 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 addition to PJM interchange activity, the Company has interconnection agreements with Allegheny Power System (APS) and Virginia Power. These agreements provide a mechanism and the flexibility to purchase power from these parties or from others with whom they are interconnected on an as-needed basis in amounts mutually agreed to from time-to-time pursuant to negotiated rates, terms and conditions. "Other purchases" includes the cost of this energy together with purchases of energy from Ohio Edison under the Company's 1987 long-term capacity purchase agreements with Ohio Edison and APS. During 1995, the Company entered into an agreement with PECO Energy Company (PECO) to purchase up to 300, but not less than 200 megawatt-hours of energy each hour beginning on June 1, 1995. The agreement will remain in effect until either party gives 30- day notice of termination. In early 1995, the Federal Energy Regulatory Commission (FERC) approved a power sales tariff, filed by the Company, which allows both sales from Company-owned generation and sales of energy purchased by the Company. This tariff expands the Company's opportunities to participate in direct energy sales with other utilities and power marketers. Through the use of similar tariffs, many other parties are now in a position to buy and sell energy. The Company is actively encouraging this market by buying energy for its own use, selling energy and buying energy for contemporaneous resale, when economic transactions are available. Pursuant to the Company's long-term capacity purchase agreements with Ohio Edison and APS, the Company is purchasing 450 megawatts of capacity and associated energy through the year 2005. The monthly capacity commitment under these agreements, excluding an allocation of fixed operating and maintenance cost, increased from $12,380 per megawatt through 1993 to $18,060 per megawatt effective January 1994, with provision for escalation in 1999. In addition, from June 1994 through May 1995, the Company purchased 147 megawatts of capacity from Pennsylvania Power and Light Company. 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 $462,000 per month. Capacity purchase payments incurred under agreements with Ohio Edison and SMECO, compare favorably with other long-term capacity and energy alternatives. 9 Other Operation and Maintenance Expenses - ---------------------------------------- Other operation and maintenance expenses totaled $316.9 million for 1995. These expenses increased by $18.2 million (6.1%) in 1995, including $15.2 million relating to the December 1994 sale and leaseback of the Company's control center system. These expenses decreased by $2.8 million (.9%) in 1994 and increased by $6.2 million (2.1%) in 1993. The Company's budget and cost control disciplines have resulted in a 16% decline in the number of Company employees since 1989. Utility operating results were also 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 will provide annual savings in operating and construction costs of approximately $15 million. Bad debt expense, as a percent of revenues, was .4% in 1995, 1994 and 1993. At December 31, 1995, accounts receivable included $23.4 million, or 9.4% of outstanding receivables, due from agencies of the District of Columbia for electric service and maintenance, of which $17.8 million, or 7.2% of outstanding receivables, was in arrears. As of February 2, 1996, the District of Columbia accounts receivable balance had been reduced to $10.2 million due to the receipt of additional payments. The Company believes that amounts owned by the District of Columbia will be paid and, accordingly, has not established a bad debt reserve for this receivable balance. Depreciation and Amortization Expense, Income Taxes and Other Taxes - ------------------------------------------------------- Depreciation and amortization expense increased by $25.5 million (14.2%), $16.4 million (10%) and $13.8 million (9.2%) in 1995, 1994 and 1993, 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 increase in income taxes in 1995 and 1994, reflects higher taxable operating income. The increase in income taxes in 1993 reflects the higher federal income tax rate which became effective in 1993 and higher taxable income. Other taxes decreased by $3.4 million (1.6%) in 1995, and increased by $4.8 million (2.4%) and $7.1 million (3.6%) in 1994 and 1993, respectively. The decrease in 1995 reflects the reduction in the county fuel-energy tax rates. The increases in 1994 and 1993 reflect changes in the levels of operating revenue and plant investment upon which taxes are based. 10 Other Income, Net Utility Interest Charges and Allowance for Funds Used During Construction - -------------------------------------------------------- Other income reflected the net (loss) earnings from PCI of $(124.4) million in 1995, $19.1 million in 1994 and $25.1 million in 1993. 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. In addition, other income, which included credits for the capital cost recovery factor associated with unamortized DSM costs, in 1994 reflects a total after-tax reduction of approximately $4.1 million in connection with District of Columbia Public Service Commission decisions. This included disallowance of rate case test period DSM program expenditures, adoption of an unbilled revenue adjustment applicable to the District of Columbia portion of the 1992 accounting change related to unbilled revenue and adoption of a three-year phase-in period to reflect increased postretirement benefit costs. In 1993, "Other, net" also included $2.8 million from the adoption of Statement of Financial Accounting Standards (SFAS) No. 109 entitled "Accounting for Income Taxes". Net utility interest charges were relatively stable during the three-year period 1993 through 1995, notwithstanding increased levels of borrowing. Short-term borrowing costs have remained relatively low and, with the refinancing of higher cost issues, the average cost of outstanding long-term utility debt declined from 8.1% at the beginning of 1993 to 7.51% at the end of 1995. Allowance For Funds Used During Construction (AFUDC) credits, which decreased during the period 1993 through 1995, relate to portions of the Company's Construction Work In Progress investment. See the Construction and Generating Capacity discussion below. In 1995, AFUDC decreased by $9.7 million, primarily due to the control center system which came on-line in December 1994. See the Capital Resources and Liquidity discussion below. CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- The Company's total investment in property and plant, at original cost, was $6.2 billion at year-end 1995. Investment in property and plant construction, net of AFUDC, was $819.7 million for the period 1993 through 1995. Internally generated cash from utility operations, after dividends, totaled $270 million for the period 1993 through 1995. Sales of First Mortgage Bonds, Medium-Term Notes and Common Stock during the period 1993 through 1995 provided a total of $1.1 billion. During the years 1993 through 1995, the Company retired 11 $896 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 1996 through 1998, capital resources of $228.8 million ($26.3 million in 1996) 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 $870 million is expected to be available from depreciation and amortization charges and income tax deferrals over the three-year period of which approximately $317 million is the 1996 portion. During 1995, the Company sold $191 million principal amount of First Mortgage Bonds, $4.6 million of Common Stock and short- term borrowings increased by $68.9 million. Proceeds were applied to meet construction requirements of $221.6 million, and scheduled debt maturities and the refinancing of higher cost debt or shorter maturity debt totaling $117.5 million. 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. Reflecting the refinancings of debt and the respective principal amounts outstanding, total annualized interest costs for all utility long-term debt outstanding at December 31, 1995, was $127.9 million, compared with $123.7 million and $114 million at December 31, 1994 and 1993, respectively. During December 1994, the Company entered into a sale (at cost) and leaseback agreement for its new control center system (system). The system is an integrated energy management system used by the Company's power dispatchers to centrally control the operation of the Company's electric system, which consists of all of its generating units, the transmission system and the distribution system. The Company has accounted for the lease of the system as a capital lease, recorded at the present value of future lease payments which totaled $152 million. This lease has been treated as an operating lease for ratemaking purposes. Dividends on preferred stock were $16.9 million in 1995, $16.4 million in 1994 and $16.3 million in 1993. The embedded cost of preferred stock was 6.43% at December 31, 1995, 6.53% at December 31, 1994 and 6.2% at December 31, 1993. 12 The Company's capitalization ratios (excluding nonutility subsidiary debt), at December 31, 1995, are presented below. - ----------------------------------------------------------------- Excluding Including Amounts Due Amounts Due In One Year In One Year - ----------------------------------------------------------------- Long-term debt 45.9% 42.8% Redeemable serial preferred stock 3.6 3.4 Serial preferred stock 3.2 3.0 Common equity 47.3 44.1 Short-term debt and amounts due in one year - 6.7 ----- ----- Total capitalization 100.0% 100.0% ===== ===== - ----------------------------------------------------------------- Year-end 1995 outstanding utility short-term indebtedness totaled $258.5 million compared with $189.6 million and $294.6 million at the end of 1994 and 1993, respectively. The Company maintains 100% line of credit back-up for its outstanding commercial promissory notes, which was unused during 1995, 1994 and 1993. Conservation - ------------ The Company's conservation and energy use management programs (EUM) 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. In 1994, the Company reevaluated its conservation programs, including additional review and consideration of the current and prospective effect of these programs on customer rates and bills. As a result of this reevaluation, the Company phased out several conservation programs and reduced rebate levels for others. In a June 1995 order, the Public Service Commission of the District of Columbia adopted conservation spending limits for the four-year period 1995 through 1998. 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. The Company expects to realize approximately 80% of the previously estimated benefits from conservation for approximately 45% of estimated cost. During 1995, the Company invested approximately $100 million in energy conservation programs. The Company recovers the costs of its conservation programs in its Maryland jurisdiction through a base rate surcharge which amortizes costs over a five-year 13 period and permits the Company to earn a return on its conservation investment while receiving compensation for lost revenue. In addition, when the Company's performance exceeds its annual goals, the Company earns a performance bonus. The Company was awarded a bonus of $8.7 million in 1995, based on 1994 performance, which followed a bonus of $5 million in 1994, based on 1993 performance. In the District of Columbia, conservation 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 conservation costs prudently incurred since June 30, 1993; prior to this decision, conservation 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 Clean Air Act Amendments of 1990. The conservation component is to be updated annually in the spring of each year, while the Clean Air Act component is updated quarterly. In 1995, approximately 157,000 customers participated in continuing energy use management 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 use 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 based on time-of-use rates. It is estimated that peak load reductions of over 600 megawatts have been achieved to date from conservation and energy use management programs and that additional peak load reductions of approximately 430 megawatts will be achieved in the next five years. The Company also estimates that, in 1995, energy savings of more than 1.2 billion kilowatt-hours have been realized through operation of its conservation and energy use management programs. During the next five years, the Company's projected costs for these programs to encourage the efficient use of electric energy and to reduce the need to build new generating facilities total $364 million ($77 million in 1996). Construction and Generating Capacity - ------------------------------------ Construction expenditures, excluding AFUDC, are projected to total $1.1 billion for the five-year period 1996 through 2000, which includes $112 million of estimated Clean Air Act expenditures. In 1996, construction expenditures are projected to total $170 million, which includes $6 million of estimated Clean Air Act expenditures. As a result of lower rates of projected load growth resulting in large part from implementing economical conservation programs, the Company previously reduced 14 its projected construction expenditures by $155 million in 1994 and $425 million in 1993. The Company plans to finance its construction program primarily through funds provided by operations. A 32-megawatt municipally financed resource recovery facility in Montgomery County, Maryland, began commercial operation in August 1995. Under the contract covering this project, the Company will initially purchase energy without capacity payment obligations. In addition, the Company has an agreement with Panda Energy Corporation for a 230-megawatt gas- fueled combined-cycle cogeneration project in Prince George's County, Maryland, scheduled for operation in the fourth quarter of 1996. The 25-year agreement currently requires capacity purchase payments to Panda Energy Corporation of approximately $1.6 million per month from January 1, 1997 through December 31, 1998. Capacity payments in 1999 and 2000 are approximately $3 million per month and generally increase thereafter, peaking at approximately $4.5 million per month. The project was financed in April 1995 and is currently one-third complete. 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. In 1995, the Maryland Public Service Commission issued an order that requires electric utilities to competitively procure future capacity resources. The Company believes that completion of the first combined-cycle unit at its Station H facility in Dickerson, Maryland, currently scheduled for 2004, is likely to be the most cost-effective alternative for the next increment of capacity. This will add a steam cycle to the two existing combustion turbine units. CLEAN AIR ACT - ------------- The Company has implemented cost-effective plans for complying with Phase I of the Clean Air Act (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 replaced 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 $112 million over the next five years. The Company's plans call for continued replacement of boiler burner equipment for nitrogen oxides emissions control and further use of lower-sulfur fuel and cofiring with natural gas for sulfur dioxide (SO2) emissions control. If economical, the Company will purchase SO2 emission allowances in lieu of burning lower-sulfur fuel. 15 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 Phase I 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 will be 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 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 which became effective during the period 1993 through 1995 are shown below. - ----------------------------------------------------------------- District of Year Total Maryland Columbia Wholesale - ----------------------------------------------------------------- (Millions of Dollars) 1995 $ 30.2 $ - $27.9 $2.3 1994 29.3 - 26.7 2.6 1993 38.1 34.3 - 3.8 ------ ----- ----- ---- $ 97.6 $34.3 $54.6 $8.7 ====== ===== ===== ==== - ----------------------------------------------------------------- Maryland - -------- Pursuant to a settlement agreement, base rate revenue was increased by $27 million, or 3%, effective November 1, 1993. The Commission previously authorized an increase in base rate revenue of $7.3 million, effective June 1, 1993, pursuant to an October 1992 settlement agreement. In connection with the settlement agreements, no determination was made with respect to rate of 16 return. The rate of return on common stock equity most recently determined for the Company in a fully litigated rate case was 12.75%, established by the Commission in a June 1991 rate increase order. The Company's Maryland DSM Surcharge, which provides for the recovery of conservation program costs over a five-year period and includes provisions for the recovery of lost revenue, a capital cost recovery factor, calculated at 9.46%, on unrecovered program balances and an incentive amount based on achieving prior-year goals, was increased effective July 1, 1995. The new rate will result in an increase in the annual surcharge recovery of approximately $29 million, including the initial amortization of 1995 projected program costs and the previously mentioned incentives of $8.7 million and $5 million for exceeding 1994 and 1993 program goals, respectively. District of Columbia - -------------------- On June 30, 1995, in Formal Case No. 939, the Commission authorized a $27.9 million, or 3.8%, increase in base rate revenue effective July 11, 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 conservation 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 conservation program expenditures, through a billing surcharge. Costs will be amortized over 10 years, with a return on unamortized amounts by means of a capital cost recovery factor computed at the authorized rate of return. The initial rate, which reflects all actual costs expended from July 1993 through December 1994, will result in $15 million of additional revenue annually. Subsequent rate updates will 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 (amounts spent in excess of the annual surcharge recovery limit, but within the four-year spending cap, are deferred for future recovery). Pre- July 1993 conservation costs receive rate base treatment. 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. 17 Wholesale - --------- The Company has a 10-year full service power supply contract with the Southern Maryland Electric Cooperative, Inc. (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, and $2.6 million effective January 1, 1994. A new agreement was recently concluded with SMECO for the years 1996 through 1998. A rate reduction of $2 million from the 1995 rate level is scheduled to become effective January 1, 1996, with an additional $2.5 million rate reduction effective January 1, 1998. Approval of the rate settlement by the Federal Energy Regulatory Commission is expected in February 1996. SMECO has agreed not to give the Company a notice of reduction or termination of service (to take effect after five years or nine years, respectively) 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, greater reliance upon long-distance transmission, 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 energy use management 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. On August 18, 1995, the Maryland Public Service Commission issued an order in a generic proceeding dealing with electric industry structure and the advent of competition. The 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 and difficult-to-find solutions. The Commission stated that it was intrigued by a restructuring concept suggested by the Company, which calls for functionally dividing the utility into generation and transmission/distribution segments. The Commission encouraged the Company to develop the concept further and suggested that other electric utilities in the state develop 18 similar proposals specific to their competitive positions. A proceeding dealing with structure and competition was initiated by the District of Columbia Commission during 1995. Based on the regulatory framework in which it operates, the Company currently applies the provisions of 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. While the Company does not foresee such a situation at this time, 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. RESTRUCTURING OF THE BULK POWER MARKET - -------------------------------------- In March 1995, the FERC issued a Notice of Proposed Rulemaking (NOPR) on competition in the wholesale energy market. The FERC's goal is to achieve greater competition in the bulk power market through open access to utilities' high voltage transmission lines. The Company, through its membership in PJM, endorses the goals of the FERC. 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. In order to meet the FERC's goals, the PJM members plan to implement significant market-oriented changes which will support broader market participation and achieve even greater efficiencies. The PJM members are working to transform today's coordinated cost- based pool dispatch into a vigorous price-based regional energy market operating under a standard of transmission service comparability. The Company, together with PJM, supports the evolution of new market-based structures to make competition truly effective. Subsequent to this NOPR, Duquesne Light Company requested that it be provided with 300 megawatts of transmission service, firm and non-firm with flexible destinations, for 20 years on the PJM and APS systems. During May 1995, FERC issued an order directing the PJM and APS companies to provide Duquesne with the transmission service it requested and to negotiate jointly the appropriate rates, terms and conditions. On June 30, 1995, a 19 "final offer" was submitted as directed by the transmitting companies. This final offer contained the allocation of the 300 megawatts among the member utilities and each company's firm transmission rates. Final briefs were filed with FERC on July 25, 1995. The transmitting companies are currently awaiting a decision from FERC. On November 30, 1995, the PJM members filed with the FERC a detailed proposal that offers to all generators and wholesale buyers of electricity a regional energy market and open access to PJM high voltage transmission lines. Under the proposal, PJM will be transformed into an Independent System Operator (ISO), which will administer a rate structure designed to eliminate dealing with each company separately for transactions through PJM. The ISO will administer operations, operate the regional energy market and administer transmission service. PJM expects to implement the new structure by year-end 1996. This change is not expected to have a material effect on the operations of the Company. THE COVE POINT JOINT VENTURE - ---------------------------- Subsidiaries of the Company and Columbia Gas System, Inc., have formed a 50/50 joint venture partnership (the Partnership) to own and operate natural gas storage and terminaling facilities at Cove Point, Maryland, and an 87-mile natural gas pipeline that extends from Cove Point to Loudoun County, Virginia. These facilities were previously owned by Columbia LNG Corporation, a Columbia Gas subsidiary. Under the agreement, Columbia LNG Corp. contributed its Cove Point terminal and pipeline assets and $7 million in cash in exchange for an equity interest in the Partnership, and the Company's subsidiaries invested $25 million in the form of equity and debt. This investment was used by the Partnership to construct a new liquefaction unit and to recommission certain existing facilities at the terminal that are being used in the peaking service business. In November 1994, the FERC approved the project based on cost-of-service rates. Commercial operation began on September 28, 1995,and to date, in accordance with the business plan, the Partnership has sold storage service for one of the four storage tanks. One of the Company's principal strategic interests in the Cove Point project is to secure a reliable and cost-effective source of transportation for gas to provide fuel to the generators at its Chalk Point Generating Station. The 87-mile Cove Point pipeline is the sole means of delivering natural gas to southern Maryland where Chalk Point is located. The FERC- approved transportation rates on the pipeline resulted in a 49% decrease from the transportation rates previously paid by the 20 Company. The Company has expanded Chalk Point's fuel flexibility to burn increased amounts of gas to comply with the CAA and minimize customer costs. JOINT VENTURE FOR WIRELESS DATA COMMUNICATION NETWORK AND NEW - ------------------------------------------------------------- ENERGY SERVICES SUBSIDIARY FORMED; W. A. CHESTER, L.L.C. -------------------------------------------------------- ACQUIRED -------- In May 1995, a subsidiary of the Company, PepData, Inc. and Metricom, Inc., entered into a joint venture agreement to own and operate a wireless data communication network which will offer economical data communication services to approximately four million people in the Washington, D.C. metropolitan area. The agreement calls for the Company to invest $7 million and to own 20 percent of the joint venture company, Metricom DC L.L.C., which will install radio devices on public and private facilities to create the wireless data communication service. This data service, known as "Ricochet," will enable computer users to access on-line services such as the Internet, E-Mail and local area networks. The service will be offered at a fixed monthly rate, which will include unlimited use of the service and access to the Internet. The joint venture is currently obtaining the necessary state and local approvals required for the deployment and operation of the communication service. Operation is expected to begin during 1996. As of December 31, 1995, the Company has invested $.1 million in the joint venture. Also in May 1995, a subsidiary, PEPCO Services, Inc., was formed to offer a range of energy-related services to businesses and government organizations in the region. The energy-related services provided by the subsidiary include assessment of existing energy systems, installation of lighting, heating, cooling and refrigeration systems including provision of financing and leasing arrangements or shared-savings arrangements, and facilities management. As of December 31, 1995, the Company has invested $1.3 million in this subsidiary. On December 31, 1995, a newly formed, wholly owned subsidiary acquired, for $1 million, the assets of the W. A. Chester Division of Fischbach Power Services, Inc., which specializes in providing underground cable construction and maintenance services for utility companies. The new company known as W. A. Chester, L.L.C. intends to provide a broad array of high-quality, cost-saving services for utility and telecommunications companies. 21 NEW ACCOUNTING STANDARD - ------------------------ In March 1995, the Financial Accounting Standards Board issued SFAS No. 121 entitled "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed Of" which will become effective for the Company's 1996 consolidated financial statements. This statement requires the Company to review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recovered. In addition, regulated companies are required to write-off regulatory assets whenever those assets no longer are probable of recovery from customers through future rates. The Company does not expect implementation of this pronouncement to have a material impact on its consolidated financial statements. 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 1995, the Company was participating 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. 22 NONUTILITY SUBSIDIARY - --------------------- RESULTS OF OPERATIONS - --------------------- In 1995, PCI incurred a net operating loss of $124.4 million ($1.05 per share) of which $122.2 million ($1.04 per share) was the result of nonrecurring, noncash, after-tax charges associated with the Company's decision to exit the aircraft equipment leasing business. This compared with contributions to consolidated net earnings of $19.1 million ($.16 per share) in 1994 and $25.1 million ($.22 per share) in 1993. As summarized below, in May 1995, PCI adopted a plan to end its investment in the aircraft equipment leasing business and made a second quarter $110 million noncash, after-tax charge against earnings. Additional noncash, after-tax charges of $12.2 million were made to recognize a noncash valuation adjustment for aircraft equipment under a master lease agreement. The plan to exit the aircraft equipment leasing business was developed following comprehensive review and analysis, and is designed to preserve value through an orderly withdrawal from the business. The decision to exit the business was based on an accumulation of factors which led to the conclusion that the aircraft leasing business was no longer consistent with PCI's goal of providing a stable supplement to consolidated earnings. These factors include the recent inability to secure satisfactory leases for certain aircraft returned by prior lessees, continuing difficulties and credit risks associated with certain lessees, and PCI's evaluation of the prospects for its aircraft lease portfolio and the airline industry in general. Under the plan, PCI will make no new investments to increase the size of the aircraft leasing portfolio. In addition, 13 aircraft, (seven L1011 aircraft, two F28-4000 aircraft, one A300 aircraft, two B747-200 aircraft and one B747-200F aircraft) were designated for sale over 18 to 24 months from the date the plan was announced. These aircraft are subject to short-term, usage- based leases, long-term leases that will expire in the near term, or are not currently under lease. Negotiations continue with respect to the sale of these aircraft. The B747-200F aircraft currently is the subject of litigation with the lessee. (See the Notes to Consolidated Financial Statements, (13) Commitments and Contingencies, Nonutility Subsidiary, for additional information.) The book value of these aircraft (which, prior to adoption of the plan, was $295 million) was reduced to an estimated net realizable value of approximately $105 million. After taking into account the elimination of a previously established reserve of approximately $22 million for future repair and maintenance expenditures and other minor adjustments, the result was an immediate noncash charge to after-tax earnings of approximately $110 million for the second quarter of 1995. 23 There will be no future depreciation of, or routine accrual for repair and maintenance expenditures with respect to, these aircraft. For accounting purposes, gains or losses from the sale of individual aircraft will be deferred until completion of the disposal process. Also as a result of differences between the guaranteed residual value and the expected market value of the two aircraft under the master lease agreement, PCI, following generally accepted accounting principles, recorded $12.2 million in additional after-tax charges against 1995 earnings. In October 1995, PCI terminated the master lease, purchasing for $52 million the two DC-10-30 aircraft on operating lease to Canadian Airlines International, Ltd. (Canadian Airlines). Depreciation and interest charges following purchase are substantially the same as the master lease rental payments. In accordance with the plan, PCI will continue to hold and closely monitor the remainder of its aircraft leasing portfolio, with the objective of identifying future opportunities for disposition of these investments on favorable terms. Included in this portion of the portfolio are two wholly owned DC-10-30 aircraft, six majority-owned aircraft (three DC-10-30 aircraft and three B747-200 aircraft) and two DC-10-30 aircraft held by partnerships in which PCI has a 50% interest, all of which are under long-term operating leases to Canadian Airlines, Continental Airlines or United Airlines. Depreciation on each of these aircraft has been increased in order to achieve book values at lease expiration that will correspond to their respective anticipated residual values. The net effect of this revised depreciation, coupled with the elimination of further depreciation on the aircraft designated for sale, will result in higher depreciation charges through 1997, and lower depreciation charges thereafter, as compared to the depreciation charges PCI would have incurred absent the plan. No adjustments were made to the remainder of PCI's aircraft leasing portfolio, which consists of 12 full or partial interests in aircraft under leveraged leases or direct finance leases (one DC-10-30 aircraft, three MD- 82 aircraft, four B737-300 aircraft, two B747-300 aircraft, one B757-200 aircraft and one MD-11F aircraft). As a part of its plan to exit the aircraft equipment leasing business, PCI has formed a joint venture with an affiliate of a major institutional investor to assist with the disposition of 19 portfolio aircraft. All the assets of the venture are fully consolidated on PCI's financial statements with the outside investor's portion reflected as minority interest. 24 In January 1995, Continental announced its intention to seek the early termination of all of its A300 aircraft leases and rental reductions under certain leases of other widebody aircraft. Following negotiations, in April 1995, PCI signed an agreement with Continental regarding this matter. As compensation for the 1995 early return and lease termination of the A300 aircraft, PCI received Continental 6% convertible debentures with an aggregate face value of $9.6 million. In November 1995, PCI sold the debentures for 97% of par value, resulting in a pre-tax gain of $7.1 million. The agreement with Continental also provides for the deferral of approximately 40% of aggregate monthly rentals from the four majority-owned and two jointly owned DC-10-30 aircraft for a period of sixteen months, commencing February 1995. The deferred amounts are to be repaid over a three and one-half year period with 8% interest, commencing June 1, 1996, at which time the aggregate deferred amount will be approximately $20 million. In addition, as part of the agreement, PCI obtained cross-default provisions in its Continental leases and improvements in aircraft return conditions. 25 PCI's aircraft portfolio at December 31, 1995 is summarized below. Aircraft Designated for Sale in Near Term Qty(1) Year(2) Lessee Lease Type - ------------------ -------------------------------------------- A-300 aircraft 1 1979 (4) N/A B747-200 aircraft 2 1976/77 (3) (4) N/A B747-200F aircraft & spare engine 1 1976 Atlas Air Operating F-28-4000 aircraft & spare engine 2 1979/80 USAir(3) Operating L1011-50 aircraft 2 1974 ING(3) Operating L1011-50 aircraft 1 1975 TWA(3) Operating L1011-100 aircraft 4 1974/75 (3) (4) N/A Aircraft With Increased Depreciation - ------------------- B747-200 aircraft & spare engine 1 1972 Continental(3) Operating B747-200 aircraft 2 1978 United(3) Operating DC-10-30 aircraft 4 1973 Continental(3) Operating DC-10-30 aircraft 1 1974 Continental(3) Operating DC-10-30 aircraft 2 1975/76 Canadian(5) Operating - ----------------------------------------------------------------- (1) Includes all equipment in which PCI has a greater than 10% ownership interest. (2) Year of manufacture. (3) PCI owns a partial interest in certain of this equipment. (4) Currently not on lease. (5) Subject to a master lease agreement prior to October 1995. 26 All Other Aircraft Equipment Qty(1) Year(2) Lessee Lease Type - ------------------ -------------------------------------------- B737-300 aircraft 4 1988 United(3) Direct Finance B747-300 Combi aircraft 1 1984 KLM(3) Leveraged B747-300 aircraft 1 1985 Singapore(3) Leveraged B757-200 aircraft 1 1986 Northwest Leveraged DC-10-30 aircraft 1 1979 Continental(3) Direct Finance MD-11F aircraft 1 1993 Fed. Express Leveraged MD-82 aircraft 1 1982 Continental(3) Direct Finance MD-82 aircraft & spare engine 2 1987 Continental(3) Direct Finance Aircraft Engines 10 Various Various Operating - ----------------------------------------------------------------- (1) Includes all equipment in which PCI has a greater than 10% ownership interest. (2) Year of manufacture. (3) PCI owns a partial interest in certain of this equipment. In September 1995, PCI purchased from and leased back to an Australian governmental entity two 350 megawatt (gross) coal- fired electric generating units located in Queensland, Australia. PCI's original equity investment totaled $96 million and is accounted for as a leveraged lease. During 1994, PCI purchased from and leased back to a Dutch electric utility company an approximate one-third undivided interest in a recently-constructed 650 megawatt (gross) base load, coal and gas-fired power plant located in The Netherlands. PCI's original equity investment totaled $60 million and is accounted for as a leveraged lease. PCI's investment in finance leases at December 31, 1995 included a net investment of $50.6 million in five 30-megawatt Solar Electric Generating Systems (SEGS) projects in the Mojave Desert in California. The Company owns 22%, 10%, 19%, 31%, and 25% of SEGS projects III through VII, respectively. During December 1995, PCI recorded a $3.2 million pretax writedown related to its investment in the SEGS III project. The five SEGS power generating projects sell electricity to Southern California Edison Company (Edison) under thirty year Interim Standard Offer No. 4 power purchase agreements which fix the capacity charge for the term of the agreement and fix the energy rate paid by Edison for the first 10 years of the agreements. For the remaining term of the agreements, energy rates are variable, based on 27 Edison's avoided cost of generation. The SEGS projects are scheduled to begin supplying electricity at avoided cost rates at various times beginning in early 1997 through the end of 1998. As a result of declines in Edison's avoided costs subsequent to the inception of these agreements, revenue at these projects currently is expected to be substantially lower than revenue presently being realized under the fixed energy price terms of the agreements. If current avoided cost levels were to continue, PCI could experience reduced earnings or incur additional losses associated with these projects. In conjunction with other project investors, PCI is investigating and pursuing alternatives for these projects, including but not limited to, renegotiating the power purchase agreements and restructuring the associated non-recourse debt. PCI generates income primarily from its leasing activities and securities investments. Income from leasing activities, which includes rental income, gains on asset sales, interest income and fees totaled $100.7 million in 1995 compared to $111.3 million in 1994 and $114.2 million in 1993. The decrease in 1995 revenue from leasing activities over 1994 was primarily due to a decrease in rental income from operating leases and reduced fee income. PCI's marketable securities portfolio contributed pre-tax income of $36.1 million in 1995 compared with $35.1 million and $38.4 million in 1994 and 1993, respectively, which results included net realized gains of $.4 million in 1995 compared with $.8 million and $7 million in 1994 and 1993, respectively. Other income decreased in 1995 compared to 1994 primarily due to a 1994 sale of real estate held for development. 28 Expenses, before income taxes, which include interest, depreciation and operating, and administrative and general expenses totaled $174.5 million in 1995 compared to $150.6 million and $159.3 million in 1994 and 1993, respectively. Expenses increased in 1995 over 1994 primarily as a result of the $18.8 million pre-tax charge in 1995 to recognize the difference between the guaranteed residual value and the expected market value of aircraft subject to the master lease agreement which expired in September 1995. Depreciation expense also increased in 1995 as a result of the plan to exit the aircraft equipment leasing business. PCI had income tax credits of $85.7 million in 1995 compared to income tax credits of $22.7 million and $45.1 million in 1994 and 1993, respectively. The increase in income tax credits in 1995 over 1994 and 1993 was the result of the previously mentioned charge relating to the decision to exit the aircraft equipment leasing business. CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- The $530.3 million securities portfolio, consisting primarily of investment grade preferred stocks, provides PCI significant liquidity and investment flexibility. Investments in leased equipment of approximately $155 million in 1995 were for the purchase of two 350 megawatt (gross) coal-fired electric generating units located in Australia for $96 million, two DC-10-30 aircraft previously under a master lease for $52 million and $7.4 million for the purchase of aircraft engines placed under operating leases. The aircraft are on operating lease to Canadian Airlines. The electric generating units were purchased and leased back under a long-term leveraged lease to an Australian governmental entity. PCI's outstanding short-term debt totaled $223.4 million at December 31, 1995, an increase of $175 million from the $48.4 million outstanding at December 31, 1994. During 1995, PCI issued $182 million in long-term debt, including non-recourse debt, and debt repayments totaled $275 million. At December 31, 1995, PCI had $394 million available under its Medium-Term Note Program and $400 million of unused short-term bank credit lines. PCI has paid a total of $100 million in dividends to PEPCO, including a $9 million dividend paid in January 1995. PCI paid a dividend of $50 million to the Company in December 1990, and subsequent dividend payments, through January 1995, have been approximately 50% of annual net earnings, with consideration given to future business plans, debt-to-equity ratios and anticipated capital requirements. 29 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 subsidiaries at December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, 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 19, 1996 30 Consolidated Statements of Earnings Potomac Electric Power Company and Subsidiaries
- ------------------------------------------------------------------------------------------------------ For the year ended December 31, 1995 1994 1993 - ------------------------------------------------------------------------------------------------------ (Thousands of Dollars) Revenue (Note 2) Operating revenue $1,822,432 $1,790,600 $1,702,442 Interchange deliveries 53,670 32,474 22,763 ---------- ---------- ---------- Total Revenue 1,876,102 1,823,074 1,725,205 ---------- ---------- ---------- Operating Expenses Fuel 355,453 392,730 354,282 Purchased energy 193,592 173,384 173,456 ---------- ---------- ---------- Fuel and purchased energy 549,045 566,114 527,738 Capacity purchase payments (Note 13) 125,769 127,822 96,288 Other operation 224,030 206,106 207,814 Maintenance 92,859 92,614 93,668 Depreciation and amortization 205,490 179,986 163,607 Income taxes (Note 4) 128,460 119,859 110,176 Other taxes (Note 5) 202,708 206,080 201,252 ---------- ---------- ---------- Total Operating Expenses 1,528,361 1,498,581 1,400,543 ---------- ---------- ---------- Operating Income 347,741 324,493 324,662 ---------- ---------- ---------- Other (Loss) Income Nonutility subsidiary (Note 15) Income 134,493 147,006 139,341 Loss on assets held for disposal (170,078) - - Expenses, including interest and income taxes (88,812) (127,918) (114,240) ---------- ---------- ---------- Net (loss) earnings from nonutility subsidiary (124,397) 19,088 25,101 Allowance for other funds used during construction 1,548 9,123 13,242 Other, net 8,549 4,046 10,221 ---------- ---------- ---------- Total Other (Loss) Income (114,300) 32,257 48,564 ---------- ---------- ---------- Income Before Utility Interest Charges 233,441 356,750 373,226 ---------- ---------- ---------- Utility Interest Charges Interest on debt 146,558 139,210 141,393 Allowance for borrowed funds used during construction (7,508) (9,622) (9,746) ---------- ---------- ---------- Net Utility Interest Charges 139,050 129,588 131,647 ---------- ---------- ---------- Net Income 94,391 227,162 241,579 Dividends on Preferred Stock 16,851 16,437 16,255 ---------- ---------- ---------- Earnings for Common Stock $ 77,540 $ 210,725 $ 225,324 ========== ========== ========== Average Common Shares Outstanding (000s) 118,412 118,006 115,640 Earnings Per Common Share $.65 $1.79 $1.95 Cash Dividends Per Common Share $1.66 $1.66 $1.64 No material dilution would occur if all of the convertible preferred stock and debentures were converted into common stock. 31
Consolidated Balance Sheets Potomac Electric Power Company and Subsidiaries
- --------------------------------------------------------------------------------------------- December 31, Assets 1995 1994 - --------------------------------------------------------------------------------------------- (Thousands of Dollars) Property and Plant - at original cost (Notes 6 and 10) Electric plant in service $ 6,041,203 $ 5,801,349 Construction work in progress 93,047 147,224 Electric plant held for future use 4,082 18,041 Nonoperating property 22,771 7,556 ----------- ----------- 6,161,103 5,974,170 Accumulated depreciation (1,760,792) (1,639,771) ----------- ----------- Net Property and Plant 4,400,311 4,334,399 ----------- ----------- Current Assets Cash and cash equivalents 5,844 7,198 Customer accounts receivable, less allowance for uncollectible accounts of $1,669 and $2,432 137,456 107,351 Other accounts receivable, less allowance for uncollectible accounts of $300 36,765 57,128 Accrued unbilled revenue (Note 1) 73,622 67,543 Prepaid taxes 36,255 34,352 Other prepaid expenses 7,562 5,448 Material and supplies - at average cost Fuel 63,203 73,671 Construction and maintenance 70,497 72,447 ----------- ----------- Total Current Assets 431,204 425,138 ----------- ----------- Deferred Charges Income taxes recoverable through future rates, net (Note 4) 244,181 251,357 Conservation costs, net 230,412 161,204 Unamortized debt reacquisition costs 58,360 56,725 Other 138,619 98,783 ----------- ----------- Total Deferred Charges 671,572 568,069 ----------- ----------- Nonutility Subsidiary Assets Cash and cash equivalents 1,594 - Marketable securities (Notes 11 and 15) 530,323 473,608 Investment in finance leases (Note 15) 489,430 410,327 Operating lease equipment, net of accumulated depreciation of $79,275 and $116,832 (Note 15) 272,947 544,064 Assets held for disposal 104,370 - Receivables, less allowance for uncollectible accounts of $6,000 and $5,000 74,957 76,426 Other investments 125,783 147,313 Other assets 15,659 22,551 ----------- ----------- Total Nonutility Subsidiary Assets 1,615,063 1,674,289 ----------- ----------- Total Assets $ 7,118,150 $ 7,001,895 =========== =========== 32
- --------------------------------------------------------------------------------------------- December 31, Capitalization and Liabilities 1995 1994 - --------------------------------------------------------------------------------------------- (Thousands of Dollars) Capitalization Common equity (Note 7) Common stock, $1 par value - authorized 200,000,000 shares, issued 118,494,577 and 118,248,103 shares $ 118,495 $ 118,248 Premium on stock and other capital contributions 1,025,088 1,020,689 Capital stock expense (14,567) (14,163) Retained income 742,296 830,524 ----------- ----------- Total Common Equity 1,871,312 1,955,298 Preference stock, cumulative, $25 par value - authorized 8,800,000 shares, no shares issued or outstanding - - Serial preferred stock (Notes 8 and 11) 125,325 125,409 Redeemable serial preferred stock (Notes 9 and 11) 143,485 143,563 Long-term debt (Notes 10 and 11) 1,817,077 1,723,399 ----------- ----------- Total Capitalization 3,957,199 3,947,669 ----------- ----------- Other Non-Current Liabilities Capital lease obligation (Note 13) 165,235 167,324 ----------- ----------- Total Other Non-Current Liabilities 165,235 167,324 ----------- ----------- Current Liabilities Long-term debt due within one year 26,280 45,445 Short-term debt (Note 12) 258,465 189,600 Accounts payable and accrued payroll 104,396 117,909 Capital lease obligation due within one year 20,772 20,772 Taxes accrued 19,111 20,509 Interest accrued 38,532 36,840 Customer deposits 23,372 22,563 Other 62,662 84,841 ----------- ----------- Total Current Liabilities 553,590 538,479 ----------- ----------- Deferred Credits Income taxes (Note 4) 892,544 848,456 Investment tax credits (Note 4) 64,607 68,256 Other 35,089 31,766 ----------- ----------- Total Deferred Credits 992,240 948,478 ----------- ----------- Nonutility Subsidiary Liabilities Long-term debt (Notes 10 and 11) 1,047,484 1,140,505 Short-term notes payable (Note 12) 223,350 48,400 Deferred taxes and other (Note 4) 179,052 211,040 ----------- ----------- Total Nonutility Subsidiary Liabilities 1,449,886 1,399,945 ----------- ----------- Commitments and Contingencies (Note 13) Total Capitalization and Liabilities $ 7,118,150 $ 7,001,895 =========== =========== 33
Consolidated Statements of Cash Flows Potomac Electric Power Company and Subsidiaries
- ----------------------------------------------------------------------------------------------------- For the year ended December 31, 1995 1994 1993 - ----------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities Income from utility operations $ 218,788 $ 208,074 $ 216,478 Adjustments to reconcile income to net cash from operating activities: Depreciation and amortization 205,490 179,986 163,607 Deferred income taxes and investment tax credits 51,774 44,641 27,711 Allowance for funds used during construction (9,056) (18,745) (22,988) Changes in materials and supplies 12,418 (13,883) 44,509 Changes in accounts receivable and accrued unbilled revenue (15,822) (6,098) (35,399) Changes in accounts payable (14,419) 8,257 (441) Changes in other current assets and liabilities (1,484) (6,760) 4,317 Changes in deferred conservation costs (104,796) (92,504) (59,639) Net other operating activities (45,664) 360 (37,121) Nonutility subsidiary: Net (loss) earnings (124,397) 19,088 25,101 Deferred income taxes (49,697) 6,386 (32,814) Loss on assets held for disposal 170,078 - - Changes in other assets and net other operating activities 83,509 47,648 56,897 --------- --------- --------- Net Cash From Operating Activities 376,722 376,450 350,218 --------- --------- --------- Investing Activities Total investment in property and plant (230,675) (316,890) (322,951) Allowance for funds used during construction 9,056 18,745 22,988 --------- --------- --------- Net investment in property and plant (221,619) (298,145) (299,963) Nonutility subsidiary: Purchase of marketable securities (35,221) (127,335) (254,213) Proceeds from sale or redemption of marketable securities 27,846 82,444 194,295 Investment in leased equipment (154,766) (72,134) (32,360) Proceeds from sale or disposition of leased equipment - 1,150 120,529 Proceeds from sale of assets 5,966 - - Purchase of other investments (3,818) (7,191) (44,628) Proceeds from sale or distribution of other investments 15,614 18,429 - Investment in promissory notes (7,955) (542) (1,628) Proceeds from promissory notes 7,977 4,902 3,013 --------- --------- --------- Net Cash Used by Investing Activities (365,976) (398,422) (314,955) --------- --------- --------- Financing Activities Dividends on common stock (196,469) (195,755) (189,837) Dividends on preferred stock (16,851) (16,437) (16,255) Issuance of common stock 4,580 9,285 96,001 Redemption of preferred stock (78) (4,047) (1,500) Issuance of long-term debt 188,594 302,999 521,264 Reacquisition and retirement of long-term debt (117,465) (144,422) (628,448) Proceeds from sale and leaseback of control center system - 152,000 - Short-term debt, net 68,865 (105,015) 233,015 Other financing activities (23,611) (14,452) (26,199) Nonutility subsidiary: Issuance of long-term debt 182,000 286,750 363,653 Repayment of long-term debt (275,021) (173,950) (247,077) Short-term debt, net 174,950 (77,850) (137,265) --------- --------- --------- Net Cash (Used by) From Financing Activities (10,506) 19,106 (32,648) --------- --------- --------- Net Increase (Decrease) In Cash and Cash Equivalents 240 (2,866) 2,615 Cash and Cash Equivalents at Beginning of Year 7,198 10,064 7,449 --------- --------- --------- Cash and Cash Equivalents at End of Year (Note 14) $ 7,438 $ 7,198 $ 10,064 ========= ========= ========= 34
Notes to Consolidated Financial Statements - ------------------------------------------ (1) Summary of Significant Accounting Policies ------------------------------------------ The Company 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), a wholly owned subsidiary of the Company, was formed in 1983 to provide a permanent vehicle for the conduct of the Company's ongoing nonutility investment programs. 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 also 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 Statement of Financial Accounting Standards (SFAS) No. 71 entitled "Accounting for the Effects of Certain Types of Regulation" in accounting for certain deferred charges and credits to be recognized in future customer billings pursuant to regulatory authorization: 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. Certain prior year amounts have been reclassified to conform to the current year presentation. A description of significant accounting policies follows. 35 Principles of Consolidation - --------------------------- The consolidated financial statements combine the financial results of the Company and all majority-owned subsidiaries. The Company's principal subsidiary is 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 to other utilities related to pooling and interconnection agreements. 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 will be updated annually on June 1 to recover 1995 and subsequent conservation expenditures, including a capital cost recovery factor, which is a mechanism that enables the Company to earn a return on certain costs, principally 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 capital cost recovery factor, incentives, applicable taxes and estimated lost revenue. The surcharge is established annually in a collaborative process with the recovery of lost revenue subject to an earnings test performed on a quarterly basis. 36 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 1995, 1994 and 1993. 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. At December 31, 1995, unamortized conservation costs totaled $105.5 million in Maryland and $124.9 million in the District of Columbia. 37 Allowance for Funds Used During Construction - -------------------------------------------- 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 Company accrues a capital cost recovery factor on the retail jurisdictional portion of certain pollution control projects related to compliance with the Clean Air Act (CAA). The base for calculating this return is the amount by which the retail jurisdictional CAA expenditure balance exceeds the CAA balance included in rate base in the Company's most recently completed base rate proceeding. The jurisdictional AFUDC capitalization rates are determined as prescribed by the FERC. The effective capitalization rates were approximately 7.9% in 1995, 7.6% in 1994 and 8.7% in 1993, compounded semiannually. 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. New Accounting Standard - ----------------------- In March 1995, the Financial Accounting Standards Board issued SFAS No. 121 entitled "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed Of" which will become effective for the Company's 1996 consolidated financial statements. This statement requires the Company to review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recovered. In addition, regulated companies are required to write-off regulatory assets whenever those assets no longer are probable of recovery from customers through future rates. The Company does not expect implementation of this pronouncement to have a material impact on its consolidated financial statements. 38 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. (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 11 electric utilities which operate on a fully integrated basis. Total revenue for each year was comprised as shown below. - ----------------------------------------------------------------- 1995 1994 1993 ------------------------------------------------- Amount % Amount % Amount % - ----------------------------------------------------------------- (Thousands of Dollars) Residential $ 543,532 30.0 $ 524,738 29.5 $ 505,173 29.8 Commercial 848,892 46.8 834,323 46.8 791,357 46.6 U.S. Government 252,144 13.9 254,030 14.2 238,192 14.0 D.C. Government 52,105 2.9 56,655 3.2 53,551 3.2 Wholesale 117,117 6.4 113,318 6.3 108,162 6.4 ---------- ----- --------- ----- ---------- ----- Sales of electricity 1,813,790 100.0 1,783,064 100.0 1,696,435 100.0 ===== ===== ===== Other electric revenue 8,642 7,536 6,007 ---------- ---------- ---------- Operating revenue 1,822,432 1,790,600 1,702,442 Interchange deliveries 53,670 32,474 22,763 ---------- ---------- ---------- Total Revenue $1,876,102 $1,823,074 $1,725,205 ========== ========== ========== - ----------------------------------------------------------------- 39 Sales of electricity include base rate revenue and fuel rate revenue. Fuel rate revenue was $526.6 million in 1995, $557.4 million in 1994 and $487.9 million in 1993. The Company's Maryland fuel rate is based on historical net fuel, interchange and emission allowance costs. 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 District of Columbia fuel rate is based upon an average of historical and projected net fuel, interchange and emission allowance costs and purchased capacity, 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 interchange costs for each billing month. The difference between the estimated costs and the actual applicable fuel and interchange costs incurred each month is reflected as an adjustment to the fuel rate in the succeeding month. Amounts received for 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 subsidiaries. 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 $13.9 million in 1995, $14.3 million in 1994 and $13.7 million in 1993. The net periodic pension cost was computed as follows. - ----------------------------------------------------------------- 1995 1994 1993 - ----------------------------------------------------------------- (Thousands of Dollars) Service cost-benefits earned $ 9,900 $10,800 $10,300 Interest cost on projected benefit obligation 28,400 26,800 25,100 Actual return on Program assets (51,900) (4,600) (24,300) Differences between actual and expected return on Program assets and net amortization 27,500 (18,700) 2,600 ------- ------- ------- Pension cost $13,900 $14,300 $13,700 ======= ======= ======= - ----------------------------------------------------------------- 41 Program assets are stated at fair value and were comprised of approximately 60% and 70% of cash equivalents and fixed income investments and the balance in equity investments at December 31, 1995 and 1994, respectively. The following table sets forth the Program's funded status and amounts recognized on the Consolidated Balance Sheets. - ----------------------------------------------------------------- 1995 1994 - ----------------------------------------------------------------- (Thousands of Dollars) Actuarial present value of benefit obligations: Program benefits: Vested benefits $(295,700) $(252,300) Nonvested benefits (44,000) (30,000) --------- --------- Accumulated benefit obligation $(339,700) $(282,300) ========= ========= Actuarial present value of projected benefit obligation $(399,400) $(338,600) Program assets at fair value 360,500 289,100 --------- --------- Projected benefit obligation in excess of Program assets (38,900) (49,500) Unrecognized actuarial loss 55,600 35,600 Unrecognized prior service cost 16,300 17,600 Unrecognized net obligation at January 1, 1987, being recognized over 18 years 300 400 --------- --------- Prepaid pension expense $ 33,300 $ 4,100 ========= ========= - ----------------------------------------------------------------- The assumed weighted average discount rate and weighted average rate of increase in future compensation levels used in determining the actuarial present value of the projected benefit obligation were 7.5% and 4% in 1995 and 8.5% and 4.5% in 1994, respectively. The assumed long-term rate of return on Program assets was 9% in 1995 and 1994. 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. The 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 42 benefits of these plans if they retire under the provisions of the Company's General Retirement 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 $9 million, $8.7 million and $9.3 million in 1995, 1994 and 1993, respectively. The following table sets forth the components of the postretirement expense. - ----------------------------------------------------------------- 1995 1994 1993 - ----------------------------------------------------------------- (Thousands of Dollars) Service cost-benefits attributable to service during the year $ 2,300 $ 2,600 $ 2,500 Interest cost on accumulated postretirement benefit obligation 4,500 4,200 4,400 Actual (return) loss on plan assets (1,900) 200 (400) Amortization of transition obligation 2,100 2,500 2,800 Difference between actual and expected return on plan assets and net amortization 2,000 (800) - ------- ------- ------- Net postretirement benefit cost $ 9,000 $ 8,700 $ 9,300 ======= ======= ======= - ----------------------------------------------------------------- 43 The following table sets forth the accumulated postretirement benefit obligation reconciled to the amounts recognized on the Consolidated Balance Sheets. - ----------------------------------------------------------------- 1995 1994 - ----------------------------------------------------------------- (Thousands of Dollars) Accumulated postretirement benefit obligation to Retirees and dependents $(40,100) $(34,600) Active employees fully eligible (9,300) (10,600) Active employees not fully eligible (15,200) (14,800) -------- -------- Total accumulated postretirement benefit obligation (64,600) (60,000) Plan assets at fair value 7,800 4,500 -------- -------- Accumulated postretirement benefit obligation in excess of plan assets (56,800) (55,500) Unrecognized transition obligation 35,800 45,200 Unrecognized actuarial loss 23,100 11,100 -------- -------- Prepaid postretirement benefit cost $ 2,100 $ 800 ======== ======== - ----------------------------------------------------------------- The Company's obligation at December 31, 1995 and 1994 was based on discount rates of 7.5% and 8.5%, respectively, and weighted average rates of increase in future compensation levels of 4% and 4.5%, respectively. The assumed health-care cost trend rate is 7.5% which declines to 5.5% after a four year period. A one percentage point increase in the health-care cost trend rate would increase the Accumulated Postretirement Benefit Obligation by $3.1 million to approximately $67.7 million and the sum of the service cost and interest cost for 1995 by approximately $.4 million. In January 1995 and 1994, the Company funded the 1995 and 1994 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 1996, the 1996 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 1995 and 1994. 44 (4) Income Taxes ------------ The provision 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 - --------------------------- - --------------------------------------------------------------------------------------------------- 1995 1994 1993 - --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Utility current tax expense Federal $ 68,492 $ 63,395 $ 69,007 State and local 9,173 8,612 9,801 --------- --------- --------- Total utility current tax expense 77,665 72,007 78,808 --------- --------- --------- Utility deferred tax expense Federal 48,339 42,070 26,784 State and local 7,084 6,221 5,100 Investment tax credits (3,649) (3,650) (3,469) --------- --------- --------- Total utility deferred tax expense 51,774 44,641 28,415 --------- --------- --------- Total utility income tax expense 129,439 116,648 107,223 --------- --------- --------- Nonutility subsidiary current tax expense Federal (35,592) (29,315) (13,022) --------- --------- --------- Nonutility subsidiary deferred tax expense Federal (50,116) 6,758 (31,360) State and local - (138) (696) --------- --------- --------- Total nonutility subsidiary deferred tax expense (50,116) 6,620 (32,056) --------- --------- --------- Total nonutility subsidiary income tax expense (85,708) (22,695) (45,078) --------- --------- --------- Total consolidated income tax expense 43,731 93,953 62,145 Income taxes included in other income (84,729) (25,906) (48,031) --------- --------- --------- Income taxes included in utility operating expenses $ 128,460 $ 119,859 $ 110,176 ========= ========= ========= 45
Reconciliation of Consolidated Income Tax Expense - ------------------------------------------------- - --------------------------------------------------------------------------------------------------- 1995 1994 1993 - --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Income before income taxes $ 138,122 $ 321,115 $ 303,724 ========= ========= ========= Utility income tax at federal statutory rate $ 121,879 $ 113,653 $ 113,295 Increases (decreases) resulting from Depreciation 9,173 8,022 5,096 Removal costs (7,204) (4,086) (4,385) Allowance for funds used during construction 595 (2,411) (3,852) Other (1,613) (4,175) (6,477) State income taxes, net of federal effect 10,648 9,683 9,686 Tax credits (4,039) (4,038) (3,873) Cumulative effect of tax rate change - - (2,267) --------- --------- --------- Total utility income tax expense 129,439 116,648 107,223 --------- --------- --------- Nonutility subsidiary income tax at federal statutory rate (73,537) (1,262) (6,992) Increases (decreases) resulting from Dividends received deduction (8,524) (8,487) (7,672) Reversal of previously accrued deferred taxes - (8,206) (35,904) Other (3,647) (4,602) (408) State income taxes, net of federal effect - (138) (696) Cumulative effect of tax rate change - - 6,594 --------- --------- --------- Total nonutility subsidiary income tax expense (85,708) (22,695) (45,078) --------- --------- --------- Total consolidated income tax expense 43,731 93,953 62,145 Income taxes included in other income (84,729) (25,906) (48,031) --------- --------- --------- Income taxes included in utility operating expenses $ 128,460 $ 119,859 $ 110,176 ========= ========= =========
Components of Consolidated Deferred Tax Liabilities (Assets) - ------------------------------------------------------------ At December 31, ---------------------- 1995 1994 ---------------------- (Thousands of Dollars) Utility deferred tax liabilities (assets) Depreciation and other book to tax basis differences $ 773,323 $ 723,248 Rapid amortization of certified pollution control facilities 26,640 29,018 Deferred taxes on amounts to be collected through future rates 92,472 95,465 Property taxes 11,808 11,212 Deferred fuel (7,154) 177 Prepayment premium on debt retirement 22,080 21,537 Deferred investment tax credit (24,464) (25,922) Contributions in aid of construction (27,206) (24,954) Contributions to pension plan 10,859 - Other 25,124 25,454 --------- --------- Total utility deferred tax liabilities (net) 903,482 855,235 Current portion of utility deferred tax liabilities (included in Other Current Liabilities) 10,938 6,779 --------- --------- Total utility deferred tax liabilities (net) - noncurrent $ 892,544 $ 848,456 ========= ========= Nonutility subsidiary deferred tax liabilities (assets) Finance leases $ 149,103 134,925 Operating leases 66,802 117,782 Reversal of previously accrued taxes related to partnerships (11,593) (16,385) Alternative minimum tax (84,512) (77,167) Other (16,840) (24,477) --------- --------- Total nonutility subsidiary deferred tax liabilities (net), (included in Deferred taxes and other) $ 102,960 $ 134,678 ========= ========= 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, 1995 and 1994. 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 subsidiaries file a consolidated federal income tax return. The Company's federal income tax liabilities for all years through 1991 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. 47 (5) Other Taxes ----------- Taxes, other than income taxes, charged to utility operating expenses for each period are shown below. - ---------------------------------------------------------------- 1995 1994 1993 - ---------------------------------------------------------------- (Thousands of Dollars) Gross receipts $ 95,158 $ 93,549 $ 88,044 Property 64,991 60,443 58,193 Payroll 11,269 11,063 10,534 County fuel-energy 21,887 30,842 34,614 Environmental, use and other 9,403 10,183 9,867 -------- -------- -------- $202,708 $206,080 $201,252 ======== ======== ======== - ----------------------------------------------------------------- 48 (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. 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 $85.7 million at December 31, 1995 and $81.1 million at December 31, 1994, includes $1.3 million and $9.5 million of Construction Work in Progress, respectively. 49 (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, 1992 114,296,443 $ 114,296 $ 919,089 $ 802,774 Net income before net earnings from nonutility subsidiary - - - 216,478 Nonutility subsidiary: Net earnings - - - 25,101 Marketable equity securities valuation allowance, net of tax - - - 1,172 Dividends: Preferred stock - - - (16,255) Common stock - - - (189,837) Conversion of convertible debentures 3,480 4 93 - Conversion of preferred stock 5,534 6 42 - Loss on acquisition of preferred stock - - (24) - Other capital contributions - - 69 - Sale of common stock through Shareholder Dividend Reinvestment Plan 1,638,227 1,638 42,655 - Issuance of common stock to Employee Savings Plans 362,468 362 9,277 - Sale of common stock through public offerings 1,491,500 1,492 40,577 - ----------- ---------- ---------- ---------- Balance, December 31, 1993 117,797,652 117,798 1,011,778 839,433 Net income before net earnings from nonutility subsidiary - - - 208,074 Nonutility subsidiary: Net earnings - - - 19,088 Marketable securities net unrealized loss, net of tax - - - (23,879) Dividends: Preferred stock - - - (16,437) Common stock - - - (195,755) Conversion of preferred stock 3,845 4 29 - Gain on acquisition of preferred stock - - 109 - Other capital reductions - - (66) - Sale of common stock through Shareholder Dividend Reinvestment Plan 355,198 355 6,603 - Issuance of common stock to Employee Savings Plans 91,408 91 2,236 - ----------- ---------- ---------- ---------- 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 =========== ========== ========== ========== 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, 1995, 39,139 shares of common stock were reserved for issuance upon the conversion of convertible preferred stock, 2,771,633 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. Under the Stock Option Agreement with Baltimore Gas and Electric Company, 23,579,900 shares could become issuable, contingent upon specific events associated with termination of the Merger Agreement. See Note (13) Commitments and Contingencies for additional information. 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, 1995. 51 (8) Serial Preferred Stock ---------------------- The Company has authorized 11,126,222 shares of cumulative $50 par value Serial Preferred Stock. At December 31, 1995 and 1994, there were outstanding 5,376,202 shares and 5,379,433 shares, respectively. The various series of Serial Preferred Stock outstanding (excluding 2,869,696 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 1995 1994 - ----------------------------------------------------------------- (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, 6,506 and 8,182 shares, respectively $50.00 325 409 Auction Series A, 1,000,000 shares $50.00 50,000 50,000 -------- -------- $125,325 $125,409 ======== ======== - ----------------------------------------------------------------- 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, 1995, 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 1,676 shares in 1995, 656 shares in 1994 and 948 shares in 1993. Dividends on the Serial Preferred Stock, Auction Series A, are cumulative and 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 4.335% ($2.1675) for the period December 1, 1995 through February 29, 1996. The average annual dividend rates were 4.638% ($2.319) in 1995 and 3.55% ($1.775) in 1994. 52 (9) Redeemable Serial Preferred Stock --------------------------------- The outstanding series of $50 par value Redeemable Serial Preferred Stock are shown below. - ----------------------------------------------------------------- December 31, 1995 1994 - ----------------------------------------------------------------- (Thousands of Dollars) $3.37 Series of 1987, 869,696 and 871,251 shares, respectively $ 43,485 $ 43,563 $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 -------- -------- $143,485 $143,563 ======== ======== - ---------------------------------------------------------------- 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 $52.25, which is reduced in succeeding years, equaling 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; however, the shares are not redeemable prior to June 1, 1996, through certain refunding operations. The redemption price 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 2000 with respect to the Redeemable Serial Preferred Stock are $1 million in 1997 and $1.5 million annually thereafter. 54 (10) Long-Term Debt
Details of long-term debt are shown below. - ------------------------------------------------------------------------------------------------------ Interest December 31, Rate Maturity 1995 1994 - ------------------------------------------------------------------------------------------------------ (Thousands of Dollars) First Mortgage Bonds Fixed Rate Series: 5% December 15, 1995 $ - $ 40,000 5-5/8% December 31, 1997 - 16,000 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 - 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 - 8-5/8% August 15, 2019 - 59,800 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 - 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 1,341,800 1,266,600 Convertible Debentures 5% September 1, 2002 115,000 115,000 7% January 15, 2018 66,747 68,412 Medium-Term Notes 6.25% May 28, 1996 25,000 25,000 6.66% to 6.73% May 1997 100,000 100,000 9.08% July and August 1997 50,000 50,000 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 ---------- ---------- Total Utility Long-Term Debt 1,873,547 1,800,012 Net unamortized discount (30,190) (31,168) Current portion (26,280) (45,445) ---------- ---------- Net Utility Long-Term Debt $1,817,077 $1,723,399 ========== ========== Nonutility Subsidiary Long-term Debt Varying rates through 2011 $1,047,484 $1,140,505 ========== ========== 55
Utility Long-Term Debt - ---------------------- The outstanding First Mortgage Bonds (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. During 1995, the Company issued $100 million of 6-1/2% First Mortgage Bonds, $75 million of 7-3/8% First Mortgage Bonds and $16 million of 5-3/4% First Mortgage Bonds with various maturities. A portion of the proceeds from these financings was used to redeem $75.8 million of higher cost or shorter maturity First Mortgage Bonds, to satisfy current long-term debt maturities of $40 million and to refund short-term debt. The interest rate on the $50 million Adjustable Rate series First Mortgage Bonds is adjusted annually on December 1, based upon 116% of the 10-year "constant maturity" United States Treasury bond rate for the preceding three-month period ended October 31. Effective December 1, 1995, the applicable interest rate is 7.443%. The applicable interest rate was 8.68% at December 1, 1994 and 6.657% at December 1, 1993. 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, 1995 are $26.3 million in 1996, $150 million in 1997, $50 million in 1998, $45 million in 1999 and $100 million in 2000. Nonutility Subsidiary Long-Term Debt - ------------------------------------ Long-term debt at December 31, 1995 consisted of $981.3 million of recourse debt from institutional lenders maturing at various dates between 1996 and 2003. The interest rates of such borrowings ranged from 5% to 10.1%. The weighted average interest rate was 7.66% at December 31, 1995, 7.47% at December 31, 1994 and 7.45% at December 31, 1993. Annual aggregate principal repayments are $230.5 million in 1996, $169.5 million in 1997, $251.3 million in 1998, $140.5 million in 1999, $93 million in 2000 and $96.5 million thereafter. 56 Long-term debt also includes $66.2 million of non-recourse debt, $42.6 million of which was 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 $23.6 million is related to PCI's majority-owned real estate partnerships of which $15.4 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 $8.2 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, 1995, and 1994 are shown below.
- ------------------------------------------------------------------------------------------------ December 31, 1995 1994 - ------------------------------------------------------------------------------------------------ Carrying Fair Carrying Fair Amount Value Amount Value ----------- ----------- ----------- ----------- (Thousands of Dollars) Utility Capitalization and Liabilities Serial preferred stock $ 125,325 114,590 125,409 102,102 Redeemable serial preferred stock $ 143,485 145,046 143,563 134,008 Long-term debt First Mortgage Bonds $1,326,560 1,385,609 1,208,076 1,093,208 Medium-Term Notes $ 323,007 336,351 347,712 324,223 Convertible Debentures $ 167,510 174,054 167,611 146,098 Nonutility Subsidiary Assets Marketable securities $ 530,323 530,323 473,608 473,608 Notes receivable $ 62,175 63,184 61,278 58,616 Liabilities Long-term debt $1,047,484 1,071,354 1,140,505 1,122,638 - ------------------------------------------------------------------------------------------------ 58
The methods and assumptions below were used to estimate, at December 31, 1995 and 1994, 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 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 the Company's Serial Preferred Stock, including Redeemable Serial Preferred Stock was based on quoted market prices or discounted cash flows using current rates of preferred stock with similar terms. 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 5.7% to 6.1%. The Company maintains a minimum 100% line of credit back-up for its outstanding commercial promissory notes, which was unused during 1995, 1994 and 1993. 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 for its outstanding commercial promissory notes, which was unused during 1995, 1994 and 1993. (13) Commitments and Contingencies ----------------------------- Proposed Merger - --------------- On September 22, 1995, the Company entered into an Agreement and Plan of Merger with Baltimore Gas and Electric Company (BGE). This Agreement provides for a strategic business combination in which each company will merge into Constellation Energy Corporation (Constellation Energy), a newly formed company to create an integrated, non-holding company structure (the Merger). Each outstanding share of the Company's common stock will be converted into the right to receive .997 of a share of common stock of Constellation Energy and each outstanding share of BGE common stock will be converted into the right to receive one share of Constellation Energy's common stock. This transaction is expected to qualify as a tax-free exchange of shares for the holders of each company's common stock and as a pooling of interests for accounting purposes. Constellation Energy will serve a population of approximately 4.5 million with approximately 1.8 million electric customers and over 530,000 natural gas customers. It is estimated that savings from the combined utility systems will approximate $1.3 billion over 10 years, net of costs to achieve. The allocation of the net savings between customers and shareholders of the Company will be determined in regulatory proceedings. The Merger requires the approval of shareholders of each company and certain regulatory agencies including the Federal Energy Regulatory Commission, the Public Service Commissions of Maryland and the District of Columbia and the Nuclear Regulatory Commission. The approval process is expected to take until the end of the first quarter of 1997 to complete. If the Merger Agreement is terminated by either the Company or BGE due to a material breach by the other party, the breaching party must pay the non-breaching party, as liquidated damages, $10 million in cash in respect of out-of-pocket expenses. The Merger Agreement also requires payment of a termination fee of $75 million in cash, plus $10 million in cash in respect of out- of-pocket expenses, by one party to the other if the Merger 60 Agreement is terminated under certain circumstances including, if either the Company or BGE terminates the Merger Agreement after the Board of Directors of the other party withdraws or adversely modifies its recommendation of the transaction. The termination fees payable by the Company under these provisions and the aggregate amount which could be payable by the Company upon a required repurchase of an option (or shares of common stock issued pursuant to the exercise of the option) granted by the Company to BGE in connection with entry into the Merger Agreement may not exceed $125 million in the aggregate. The Company has approved a severance plan for all exempt and non-bargaining unit employees who lose employment due to the Merger. Employees who lose employment as a result of the Merger will receive two weeks of pay per year of service, with a minimum payment of eight weeks of pay. In addition, employees will receive company-subsidized health and dental insurance for two weeks for each year of service, with a minimum of eight weeks of insurance coverage. In December 1995, an extension of the current 1993 Labor Agreement between the Company and Local 1900 of the International Brotherhood of Electrical Workers was ratified by the Union members. The 1995 Agreement extends the 1993 Agreement, which was due to expire on June 1, 1996, for two years or until the effective date of the Merger with BGE, whichever occurs first. This Agreement provides severance benefits, previously approved by the Company for exempt and non-bargaining unit employees, for all union members and provides for a lump-sum payment of 2% of base pay on January 5, 1996, a lump-sum payment of 1% of base pay on June 7, 1996 and a lump-sum payment of 3% of base pay on June 6, 1997 or the effective date of the Merger, whichever occurs first. Leases - ------ The Company leases its general office building and certain data processing and duplicating equipment, motor vehicles, communication system and construction equipment under long-term lease agreements. The lease of the general office building expires in 2002 and leases of equipment extend for periods of up to 6 years. Charges under such leases are accounted for as operating expenses or construction expenditures, as appropriate. Rents, including property taxes and insurance, net of rental income from subleases, aggregated approximately $15.6 million in 1995, $14.9 million in 1994 and $13.6 million in 1993. The approximate annual commitments under all operating leases, reduced by rentals to be received under subleases are $13.8 million in 1996, $7.7 million in 1997, $6.2 million in 1998, $5.6 million in 1999, $4.6 million in 2000 and a total of $10.8 million in the years thereafter. 61 The Company entered into a sale (at cost) and leaseback agreement, in December 1994, for its control center system (system). The system is an integrated energy management system used by the Company's power dispatchers to centrally control the operation of the Company's electric system, which consists of all of its generating units, the transmission system and the distribution system. The lease of the system 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. Fuel Contracts - -------------- The Company has numerous coal contracts with various expiration dates through 2003 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 1996. Approximately 52% of the estimated system coal requirements in 1996 will be purchased 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 APS commenced June 1, 1987 and are expected to continue at the 450 megawatt level through 2005. Under the terms of the agreement with Ohio Edison, 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 approximate monthly capacity commitment under this agreement, excluding an allocation of fixed operating and maintenance cost, is $18,060 per megawatt through 1998 and $25,620 per megawatt from 1999 through 2005. 62 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 $462,000 per month. 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. The Company has a 25-year agreement with Panda Energy Corporation for 230 megawatts of capacity supplied by a gas- fueled combined-cycle cogenerator which is scheduled for operation in the fourth quarter of 1996. The agreement currently requires capacity purchase payments to Panda Energy Corporation of approximately $1.6 million per month from January 1, 1997 through December 31, 1998. Capacity payments in 1999 and 2000 are approximately $3 million per month and generally increase thereafter peaking at approximately $4.5 million per month. 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. During 1993, the Company and two other potentially responsible parties (PRP) completed a removal action at a site in Harmony, West Virginia pursuant to an Administrative Order (AO) issued by the U.S. Environmental Protection Agency (EPA). Approximately $3 million (of which the Company has paid one- third, subject to possible reallocation) was expended on the removal action, which the EPA has stated is in compliance with the AO. The Company and two other PRPs have entered into settlements with third parties to recover approximately $2.4 million of this cost. EPA oversight costs, which are not expected to be material, have not yet been assessed. While compliance with the AO has been completed, the Company cannot determine whether it will be subject to any future liability with respect to this site. 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 63 to the issuance of a Record of Decision (ROD) by the EPA, including legal fees, are currently estimated to be $5.6 million. The Company has paid $2.5 million as of December 31, 1995. The report included a number of possible remedies, the estimated costs of which range from $2 million to $90 million. On July 20, 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. On October 3, 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. On December 5, 1995, the Company received notice from the EPA that it is a PRP under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA or Superfund) 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. A preliminary investigation by the Company 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. Litigation - ---------- During 1993, the Company was served with Amended Complaints filed in three jurisdictions (Prince George's County, Baltimore City, and Baltimore County), in separate ongoing, consolidated proceedings each denominated "In re: Personal Injury Asbestos Case." The Company (and other defendants) were brought into 64 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 four hundred and forty-eight (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 filings, a number of the individual suits have been disposed of without any payment by 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. While the aggregate amount specified in the remaining suits would exceed $1 billion, 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. Nonutility Subsidiary - --------------------- In May 1995, PCI adopted a plan to exit the aircraft equipment leasing business. The plan, which was developed following comprehensive review, is designed to permit a withdrawal from the aircraft leasing business on an orderly basis designed to preserve value. Under the plan, PCI will make no new investments to increase the size of the aircraft leasing portfolio. In 65 addition, thirteen aircraft have been designated for sale over 18 to 24 months from the date the plan was announced. These aircraft are subject to short-term, usage-based leases, long-term leases that will expire in the near term, or are not currently under lease. The book value of these aircraft (which, prior to adoption of the plan, was $295 million) was reduced to an estimated net realizable value of approximately $105 million. After taking into account the elimination of a previously established reserve of approximately $22 million for future repair and maintenance expenditures and other minor adjustments, the result was an immediate non-cash charge to after-tax earnings of approximately $110 million for the second quarter of 1995. There will be no future depreciation of, or routine accrual for repair and maintenance expenditures with respect to, these aircraft. For accounting purposes, gains or losses from the sale of individual aircraft will be deferred until completion of the disposal process. In accordance with the plan, PCI will continue to hold and closely monitor the remainder of its aircraft leasing portfolio, with the objective of identifying future opportunities for disposition of these investments on favorable terms. Depreciation on two wholly owned aircraft, six majority owned aircraft and two aircraft held by partnerships, in which PCI has a 50% interest, has been increased in order to achieve book values at lease expiration that will correspond to their respective anticipated residual values. The net effect of this revised depreciation, coupled with the elimination of further depreciation on the aircraft designated for sale, will result in higher depreciation charges through 1997, and lower depreciation charges thereafter, as compared to the depreciation charges PCI would have incurred absent the plan. No adjustments were made to the remainder of PCI's aircraft leasing portfolio, which consists of twelve full or partial interests in aircraft under leveraged leases or direct finance leases. PCI will continue to market and sell the thirteen aircraft designated for sale and will continue to closely monitor the aircraft in its portfolio not designated for near term sale with the objective of identifying future opportunities for sale or other disposition on favorable terms. Satisfactory execution of the entire plan may be affected by future aircraft market conditions and events, which may have an impact on equipment values and sales opportunities and, in the case of the portion of the portfolio on long term lease, the creditworthiness of PCI's lessees. In April 1995, PCI reached agreement with Continental providing for the deferral of approximately 40% of aggregate monthly rentals from the four majority-owned and two jointly owned DC-10-30 aircraft for a period of sixteen months, commencing February 1995. The deferred amounts are to be repaid over a three and one-half year period with 8% interest, 66 commencing June 1, 1996, at which time the aggregate deferred amount will be approximately $20 million. As part of the agreement, PCI obtained cross-default provisions in its Continental leases and improvements in aircraft return conditions. During July 1995, Atlas Air, Inc. filed suit in New York Superior Court requesting a declaratory judgment that the duration of its lease of one B-747-200F aircraft from PCI may be extended by Atlas, without PCI's consent, from December 1995 until as late as December 1999. On August 22, 1995, PCI filed its answer to Atlas' complaint, stating that Atlas' position is contrary to the plain meaning of the lease agreement and Atlas' own prior course of conduct acknowledging the December 1995 lease termination date. Cross-motions for summary judgment were filed, and the Court ruled in Atlas favor on December 27, 1995. A new and separate complaint, based on PCI's termination of the lease agreement because of Atlas' failure to make certain lease payments, was filed by PCI on December 29, 1995. The parties have agreed to an expedited procedural schedule, and PCI's motion for summary judgment was submitted on January 10, 1996. Management is of the opinion that the outcome of this litigation will not have a material adverse effect on its financial position or results of operations. 67 (14) Supplemental Disclosure of Cash Flow Information ------------------------------------------------ Listed below is supplemental disclosure of cash flow information. - ----------------------------------------------------------------- 1995 1994 1993 - ----------------------------------------------------------------- (Thousands of Dollars) Cash paid for: Interest, net of capitalized interest (including nonutility subsidiary interest of $93,672, $83,724 and $76,556) $223,789 203,013 206,955 Income taxes $ 44,725 51,368 67,741 Nonutility subsidiary noncash transactions: Consolidation of majority-owned subsidiaries $ - - 35,320 - ----------------------------------------------------------------- For purposes of the consolidated financial statements, cash and cash equivalents include cash on hand, money market funds and commercial paper with maturities of three months or less. 68 (15) Selected Nonutility Subsidiary Financial Information ---------------------------------------------------- Selected financial information of the Company's principal consolidated nonutility investment subsidiary, Potomac Capital Investment Corporation (PCI) and its subsidiaries, is presented below. Subsidiary equity at December 31, 1995 and December 31, 1994 was $168.4 million and $271.1 million, respectively. These amounts include $6.8 million of unrealized appreciation and $23.9 million of unrealized depreciation, respectively, at December 31, 1995 and 1994 relating to the marketable securities portfolio on an after-tax basis. PCI paid dividends to the parent Company of $9 million in 1995 and $15 million in 1994. - ----------------------------------------------------------------- For the year ended December 31, 1995 1994 1993 - ----------------------------------------------------------------- (Thousands of Dollars) Income Leasing activities $ 100,640 $111,262 $114,226 Marketable securities 36,121 35,148 38,417 Other (2,268) 596 (13,302) --------- -------- -------- 134,493 147,006 139,341 --------- -------- -------- Loss on assets held for disposal (170,078) - - --------- -------- -------- Expenses Interest 91,637 84,783 77,861 Administrative and general 10,479 10,259 14,640 Depreciation and operating 72,404 55,571 66,817 Income tax credit (85,708) (22,695) (45,078) --------- -------- -------- 88,812 127,918 114,240 --------- -------- -------- Net (loss) earnings from nonutility subsidiary $(124,397) $ 19,088 $ 25,101 ========= ======== ======== 69 Marketable Securities - --------------------- PCI's marketable securities are classified as available-for-sale for financial reporting purposes. Investment grade preferred stocks with mandatory redemption features made up 96% of the portfolio at December 31, 1995. Net unrealized gains and losses on such securities are reflected, net of tax, in stockholder's equity. 70
- ------------------------------------------------------------------------------------------- December 31, 1995 1994 ----------------------------------------------------------------- Net Market Unrealized Market Cost Value Gain (Loss) Cost Value - ------------------------------------------------------------------------------------------- (Thousands of Dollars) Mandatory redeemable preferred stock $ 519,488 $ 530,115 $ 10,627 $ 511,791 $ 473,608 Equity securities 341 208 (133) 3 - ---------- ---------- ----------- ---------- ---------- Total $ 519,829 $ 530,323 $ 10,494 $ 511,794 $ 473,608 ========== ========== =========== ========== ========== - ------------------------------------------------------------------------------------------- 71
Included in net unrealized gains and losses are gross unrealized gains of $17.1 million and gross unrealized losses of $6.6 million at December 31, 1995 and gross unrealized gains of $1.8 million and gross unrealized losses of $40 million at December 31, 1994. In determining gross realized gains and losses on sales or maturities of securities, specific identification is used. Gross realized gains were $.8 million and $2.9 million for 1995 and 1994, respectively. Gross realized losses were $.4 million and $2.1 million for 1995 and 1994, respectively. Net recognized gains from marketable securities amounted to $7 million in 1993. At December 31, 1995, the contractual maturities for mandatory redeemable preferred stock are $65.1 million within one year, $93 million from one to five years, $115.8 million from five to 10 years and $245.6 million for over 10 years. 72 Leasing Activities - ------------------ PCI's net investment in finance leases are summarized below. - ----------------------------------------------------------------- December 31, 1995 1994 - ----------------------------------------------------------------- (Thousands of Dollars) Rents receivable $691,371 $517,052 Estimated residual values 153,815 153,814 Less: Unearned and deferred income (355,756) (260,539) -------- -------- Investment in finance leases 489,430 410,327 Less: Deferred taxes arising from finance leases (149,103) (134,925) -------- -------- Net investment in finance leases $340,327 $275,402 ======== ======== - ----------------------------------------------------------------- Minimum lease payments receivable from finance leases, primarily aircraft, for each of the years 1996 through 2000 are $32.3 million, $27.1 million, $31.2 million, $30 million and $32.8 million, respectively. Net income from leveraged leases was $11 million in 1995, $5.6 million in 1994 and $1.1 million in 1993. Rent payments receivable from aircraft equipment operating leases for each of the years 1996 through 2000 are $46.4 million in 1996, $38.8 million in 1997, $31.4 million in 1998, $25.3 million in 1999 and $25.1 million in 2000. In September 1995, PCI purchased from and leased back to an Australian governmental entity two 350 megawatt (gross) coal- fired electric generating units located in Queensland, Australia. PCI's original equity investment totaled $96 million and is being accounted for as a leveraged lease. During 1994, PCI purchased from and leased back to a Dutch electric utility company an approximate one-third undivided interest in a recently-constructed 650 megawatt (gross) baseload, coal and gas-fired power plant located in The Netherlands. PCI's original equity investment totaled $60 million and is accounted for as a leveraged lease. 73 (16) Quarterly Financial Summary (Unaudited)
- --------------------------------------------------------------------------------------------------------------------- 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter Total - --------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars except Per Share Data) 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 Dividends Per Share $ .415 .415 .415 .415 1.66 1994 Operating Revenue $ 374,910 458,431 605,023 352,236 1,790,600 Total Revenue $ 393,044 467,451 607,476 355,103 1,823,074 Operating Expenses $ 355,708 370,439 447,020 325,414 1,498,581 Operating Income $ 37,336 97,012 160,456 29,689 324,493 Net Income $ 14,414 64,293 134,702 13,753 227,162 Earnings for Common Stock $ 10,268 60,224 130,576 9,657 210,725 Earnings Per Common Share $ .09 .51 1.11 .08 1.79 Dividends Per Share $ .415 .415 .415 .415 1.66 1993 Operating Revenue $ 331,236 416,152 610,540 344,514 1,702,442 Total Revenue $ 339,455 419,693 614,261 351,796 1,725,205 Operating Expenses $ 302,833 332,796 442,306 322,608 1,400,543 Operating Income $ 36,622 86,897 171,955 29,188 324,662 Net Income $ 13,044 77,022 144,671 6,842 241,579 Earnings for Common Stock $ 8,931 72,974 140,631 2,788 225,324 Earnings Per Common Share $ .08 .63 1.21 .02 1.95 Dividends Per Share $ .41 .41 .41 .41 1.64 The Company's sales of electric energy are seasonal and, accordingly, comparisons by quarter within a year are not meaningful. The total of the four quarterly earnings per share may not equal the earnings per share for the year due to changes in the number of common shares outstanding during the year. 74
Stock Market Information
- --------------------------------------------------------------------------------------------------------------------------------- 1995 High Low 1994 High Low - --------------------------------------------------------------------------------------------------------------------------------- 1st Quarter $20-1/8 $18-3/8 1st Quarter $26-5/8 $21-3/4 2nd Quarter $22-1/2 $18-1/2 2nd Quarter $23-1/2 $18-1/2 3rd Quarter $24-5/8 $20-1/2 3rd Quarter $21-1/2 $18-3/8 4th Quarter $26-1/4 $24 4th Quarter $19-3/4 $18-1/4 (Close $26-1/4) (Close $18-3/8) Shareholders at December 31, 1995: 96,958 - ---------------------------------------------------------------------------------------------------------------------------------
Selected Consolidated Financial Data
- --------------------------------------------------------------------------------------------------------------------------------- 1995 1994 1993 1992 1991 1990 1985 - --------------------------------------------------------------------------------------------------------------------------------- (Thousands except Per Share Data) Operating Revenue $1,822,432 1,790,600 1,702,442 1,562,167 1,552,066 1,411,713 1,315,699 Total Revenue $1,876,102 1,823,074 1,725,205 1,601,558 1,619,315 1,501,728 1,398,768 Operating Expenses $1,528,361 1,498,581 1,400,543 1,322,105 1,329,084 1,245,579 1,144,436 Net (Loss) Earnings from Nonutility Subsidiary $ (124,397) 19,088 25,101 28,161 23,351 5,035 14,878 Income Before Cumulative Effect of Accounting Change $ 94,391 227,162 241,579 200,760 210,164 170,234 183,618 Cumulative Effect of Accounting Change, Net of Income Taxes $ - - - 16,022 - - - Net Income $ 94,391 227,162 241,579 216,782 210,164 170,234 183,618 Earnings for Common Stock $ 77,540 210,725 225,324 202,390 197,866 159,636 169,093 Average Common Shares Outstanding 118,412 118,006 115,640 112,390 105,911 98,621 94,230 Earnings (Loss) Per Common Share Utility Operations $ 1.70 1.63 1.73 1.55 1.65 1.57 1.63 Nonutility Subsidiary $ (1.05) .16 .22 .25 .22 .05 .16 Consolidated $ .65 1.79 1.95 1.80 1.87 1.62 1.79 Cash Dividends Per Common Share $ 1.66 1.66 1.64 1.60 1.56 1.52 1.08 Investment in Property and Plant $6,161,103 5,974,170 5,701,550 5,404,265 5,084,964 4,695,966 3,339,911 Net Investment in Property and Plant $4,400,311 4,334,399 4,167,551 3,967,898 3,743,709 3,434,678 2,454,559 Utility Assets $5,503,087 5,327,606 5,036,737 4,515,403 4,211,556 3,889,101 2,881,110 Nonutility Subsidiary Assets $1,615,063 1,674,289 1,665,132 1,663,508 1,679,079 1,387,247 366,704 Total Assets $7,118,150 7,001,895 6,701,869 6,178,911 5,890,635 5,276,348 3,247,814 Long-Term Utility Obligations (including redeemable preferred stock) $1,960,562 1,866,962 1,736,621 1,727,609 1,662,157 1,516,073 1,144,671 - --------------------------------------------------------------------------------------------------------------------------------- Includes $.14 as the cumulative effect of an accounting change for unbilled revenue.
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