-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, sQUGlPC+VsmhdnTucwvNXar16bqDk1F/Qu2L0kZ6l9UXRjV0wlnPk/TCQmCUdxC1 mD1qMkU0HFXwEX01/8QG2A== 0000079732-95-000009.txt : 19950608 0000079732-95-000009.hdr.sgml : 19950608 ACCESSION NUMBER: 0000079732-95-000009 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19950127 ITEM INFORMATION: Financial statements and exhibits FILED AS OF DATE: 19950127 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: 95503433 BUSINESS ADDRESS: STREET 1: 1900 PENNSYLVANIA AVE NW STREET 2: C/O M T HOWARD RM 841 CITY: WASHINGTON STATE: DC ZIP: 20068 BUSINESS PHONE: 2028722456 8-K 1 CURRENT REPORT SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 Form 8-K CURRENT REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of Report (Date of earliest event reported) January 27, 1995 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) 872-2456 PEPCO Form 8-K Item 7. Financial Statements, Pro-Forma Financial Information and Exhibits. Exhibits Exhibit No. Description of Exhibit Reference 12 Computation of ratios............Filed herewith. 23 Consent of Independent Accountants......................Filed herewith. 27 Financial Data Schedule..........Filed herewith. 99 The 1994 consolidated financial statements of the Company and Subsidiaries, together with the report thereon of Price Waterhouse dated January 26, 1995; and Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition as well as selected financial data...................Filed herewith. Signatures Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized. Potomac Electric Power Company (Registrant) /s/ H. Lowell Davis By ___________________________ H. Lowell Davis Vice Chairman and Chief Financial Officer January 27, 1995 DATE 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 1994 through 1990 on the basis of parent company operations only, are as follows.
For The Year Ended December 31, ----------------------------------------------------- 1994 1993 1992 1991 1990 --------- --------- --------- --------- --------- (Thousands of Dollars) Net income before cumulative effect of accounting change $208,074 $216,478 $172,599 $186,813 $165,199 Taxes based on income 116,648 107,223 76,965 80,988 70,962 -------- -------- -------- -------- -------- Income before taxes and cumulative effect of accounting change 324,722 323,701 249,564 267,801 236,161 -------- -------- -------- -------- -------- Fixed charges: Interest charges 139,210 141,393 138,097 138,512 127,386 Interest factor in rentals 6,300 5,859 6,140 5,690 4,237 -------- -------- -------- -------- -------- Total fixed charges 145,510 147,252 144,237 144,202 131,623 -------- -------- -------- -------- -------- Income before income taxes, cumulative effect of accounting change and fixed charges $470,232 $470,953 $393,801 $412,003 $367,784 ======== ======== ======== ======== ======== Coverage of fixed charges 3.23 3.20 2.73 2.86 2.79 ==== ==== ==== ==== ==== Preferred dividend requirements $16,437 $16,255 $14,392 $12,298 $10,598 -------- -------- -------- -------- -------- Ratio of pre-tax income to net income 1.56 1.50 1.45 1.43 1.43 ---- ---- ---- ---- ---- Preferred dividend factor $25,642 $24,383 $20,868 $17,586 $15,155 -------- -------- -------- -------- -------- Total fixed charges and preferred dividends $171,152 $171,635 $165,105 $161,788 $146,778 ======== ======== ======== ======== ======== Coverage of combined fixed charges and preferred dividends 2.75 2.74 2.39 2.55 2.51 ==== ==== ==== ==== ====
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 1994 through 1990 on a fully consolidated basis are as follows.
For The Year Ended December 31, ----------------------------------------------------- 1994 1993 1992 1991 1990 --------- --------- --------- --------- --------- (Thousands of Dollars) Net income before cumulative effect of accounting change $227,162 $241,579 $200,760 $210,164 $170,234 Taxes based on income 93,953 62,145 79,481 80,737 63,360 -------- -------- -------- -------- -------- Income before taxes and cumulative effect of accounting change 321,115 303,724 280,241 290,901 233,594 -------- -------- -------- -------- -------- Fixed charges: Interest charges 224,514 221,312 226,453 225,323 199,469 Interest factor in rentals 9,938 9,257 6,599 6,080 4,559 -------- -------- -------- -------- -------- Total fixed charges 234,452 230,569 233,052 231,403 204,028 -------- -------- -------- -------- -------- Nonutility subsidiary capitalized interest (521) (2,059) (2,200) (6,542) - -------- -------- -------- -------- -------- Income before income taxes, cumulative effect of accounting change and fixed charges $555,046 $532,234 $511,093 $515,762 $437,622 ======== ======== ======== ======== ======== Coverage of fixed charges 2.37 2.31 2.19 2.23 2.14 ==== ==== ==== ==== ==== Preferred dividend requirements $16,437 $16,255 $14,392 $12,298 $10,598 -------- -------- -------- -------- -------- Ratio of pre-tax income to net income 1.41 1.26 1.40 1.38 1.37 ---- ---- ---- ---- ---- Preferred dividend factor $23,176 $20,481 $20,149 $16,971 $14,519 -------- -------- -------- -------- -------- Total fixed charges and preferred dividends $257,628 $251,050 $253,201 $248,374 $218,547 ======== ======== ======== ======== ======== Coverage of combined fixed charges and preferred dividends 2.15 2.12 2.02 2.08 2.00 ==== ==== ==== ==== ====
EX-23 3 PRICE WATERHOUSE CONSENT LETTER 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 (Number 33-36798, 33-53685 and 33-54197) and on Form S-3 (Numbers 33-58810 and 33-50377) of Potomac Electric Power Company of our report dated January 26, 1995 appearing on page 26 of Exhibit 99 of the Current Report on Form 8-K of Potomac Electric Power Company dated January 27, 1995. /s/ Price Waterhouse LLP Price Waterhouse LLP Washington, D.C. January 27, 1995 EX-27 4 FINANCIAL DATA SCHEDULE
UT 1 POTOMAC CAPITAL INVESTMENT CORPORATION 1,000 12-MOS DEC-31-1994 JAN-01-1994 DEC-31-1994 PER-BOOK 4,291,295 0 430,081 563,126 1,681,254 6,965,756 118,248 1,006,526 830,524 1,955,298 143,563 125,409 1,723,399 0 0 189,600 45,445 0 136,723 15,233 2,631,086 6,965,756 1,823,074 119,859 1,378,722 1,498,581 324,493 32,257 356,750 129,588 227,162 16,437 210,725 195,755 123,700 376,450 $1.79 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, 1994. No material dilution would occur if all the convertible preferred stock and debentures were converted into common stock.
EX-99 5 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.......................... 26 Consolidated Statements of Earnings........................ 27 Consolidated Balance Sheets................................ 28 Consolidated Statements of Cash Flows...................... 30 Notes to Consolidated Financial Statements................. 31 Selected Consolidated Financial Data....................... 69 1 Management's Discussion and Analysis of Consolidated Results of Operations and Financial Condition - ---------------------------------------------------- GENERAL - ------- As an investor-owned electric utility, Potomac Electric Power Company (the Company, PEPCO) 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 48% of the Company's total revenue in 1994. Fuel and purchased energy, capacity purchase payments and other operating expenses were 52% 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 1992 through 1994 for the Company and PCI. The Company's earnings for common stock during 1994 totaled $210.7 million, as compared to $225.3 million in 1993. As set forth below, earnings per share for common stock decreased from $1.95 in 1993 to $1.79 for 1994. The 1992 earnings per share amount from utility operations shown below includes $.14 as the cumulative effect of an accounting change for unbilled revenue. - ----------------------------------------------------------------- 1994 1993 1992 - ----------------------------------------------------------------- Utility Operations $1.63 $1.73 $1.55 Nonutility Subsidiary .16 .22 .25 ----- ----- ----- Consolidated $1.79 $1.95 $1.80 ===== ===== ===== - ---------------------------------------------------------------- The average number of common shares outstanding at December 31, 1994 increased by 2.4 million shares as compared to December 31, 1993. Utility earnings for 1994 reflect the effect on electricity sales and revenue of mild weather during the 1994 summer cooling season as compared to the unseasonably hot weather during the 1993 summer cooling season, partially offset by the continued effect of the 1993 base rate increases in Maryland. Although 1994 revenue increased as a result of the base rate increase authorized by the District of Columbia during the year, the 2 earnings impact was limited since this revenue increase was substantially offset by write-offs resulting from the rate order, as explained in the discussion of "Other Income" below. UTILITY - ------- Results of Operations - --------------------- Total Revenue - ------------- The changes in total revenue are shown in the following table. - ----------------------------------------------------------------- Increase (Decrease) from Prior Year 1994 1993 1992 - ----------------------------------------------------------------- (Millions of Dollars) Change in kilowatt-hour sales $(18.7) $ 87.0 $(39.1) Change in base rate revenue 32.2 45.4 71.8 Change in fuel adjustment clause billings to cover cost of fuel and interchange 73.2 8.0 (19.2) Change in other revenue 1.5 (.1) (3.4) ------ ----- ----- Change in Operating Revenue 88.2 140.3 10.1 ------ ------ ------ Change in interchange deliveries 9.7 (16.7) (27.9) ------ ------ ------ Change in Total Revenue $ 97.9 $123.6 $(17.8) ====== ====== ====== - ----------------------------------------------------------------- The $32.2 million change in 1994 base rate revenue 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 of June through October as compared to the warmer than average weather during the corresponding period in 1993. Summer period base rates are high to encourage customer conservation and peak load shifting. In addition, 1994 base rate revenue reflects approximately $5 million for achieving specified 1993 Maryland energy goals associated with the conservation incentive provision of the Company's Demand Side Management (DSM) surcharge tariff. 3 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. Base rate revenue for 1992 compared to 1991 was increased by approximately $9 million from a gross receipts tax rate increase implemented in the District of Columbia in July 1991, and in effect throughout 1992, and approximately $14 million from higher fuel and energy taxes in Montgomery County, Maryland; also by a $30.4 million District of Columbia rate increase (effective July 1992) and a $25.3 million Maryland rate increase, of which $18 million became effective in December 1992. Mild weather during the peak period summer billing months June through October had an adverse effect on 1992 revenue. An increase in 1994 and decreases in 1993 and 1992 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 continue to be a component of the Company's fuel rates. 4 Kilowatt-hour Sales - ------------------- - ----------------------------------------------------------------- 1994 1993 vs. vs. 1994 1993 1992 1993 1992 - ----------------------------------------------------------------- (Millions of Kilowatt-hours) By Customer Type Residential 6,574 6,727 6,142 (2.3)% 9.5% Commercial 11,685 11,751 11,391 (.6) 3.2 U.S. Government 4,010 3,986 3,948 .6 1.0 D.C. Government 914 903 873 1.2 3.4 Wholesale 2,363 2,327 2,130 1.5 9.2 ------ ------ ------ Total energy sales 25,546 25,694 24,484 (.6) 4.9 ====== ====== ====== Interchange Energy deliveries 800 483 771 65.6 (37.4) ====== ====== ====== By Geographic Area Maryland, including wholesale 15,251 15,319 14,441 (.4) 6.1 District of Columbia 10,295 10,375 10,043 (.8) 3.3 ------ ------ ------ Total energy sales 25,546 25,694 24,484 (.6) 4.9 ====== ====== ====== - ----------------------------------------------------------------- The slight decrease in kilowatt-hour sales in 1994, following a 4.9% increase in 1993, reflects primarily decreased customer usage of electricity during the summer cooling season (June through October) due to mild weather during these months as compared to the unseasonably hot weather during the same period in 1993, partially offset by an increase of .9% in the number of customers. Cooling degree hours during 1994 were 14% below those in 1993 and 5% above the 20-year average. The increase in kilowatt-hour sales in 1993 compared to 1992 reflects increased customer usage during the summer cooling season due to warmer than average weather. Cooling degree hours during 1993 were 97% above those in 1992 and 22% above the 20-year average. Assuming future weather conditions approximate historical averages, the Company expects its compound annual growth in kilowatt-hour sales to range between 1% and 2% over the next decade. The Company's 1994 summer peak demand was 5,660 megawatts, 1.6% below the 1993 summer peak demand of 5,754 megawatts and 1.9% below 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 6,723 megawatts. To meet the 1994 summer peak demand, the Company had 5 256 megawatts available from its dispatchable energy use management programs. Based on average weather conditions, the Company estimates that its peak demand will grow at a compound annual rate of approximately 1%, reflecting continuing emphasis on conservation and energy use management programs and anticipated service area growth trends. The all-time winter peak demand of 5,010 megawatts was established in January 1994, which was 11.1% above the previous winter peak demand of 4,511 megawatts which occurred in December 1989. Operating Expenses - ------------------ Fuel, Purchased Energy and Capacity Purchase Payments - ----------------------------------------------------- 1994 1993 1992 - ----------------------------------------------------------------- (Millions of Dollars) Fuel expense $392.7 $354.3 $345.5 ------ ------ ------ Purchased energy PJM receipts 108.8 108.9 94.6 Other purchases 64.6 64.5 72.0 ------ ------ ------ Total purchased energy 173.4 173.4 166.6 ------ ------ ------ Fuel and purchased energy $566.1 $527.7 $512.1 ====== ====== ====== Capacity purchase payments $127.8 $ 96.3 $ 95.5 ====== ====== ====== - ----------------------------------------------------------------- Net System Generation and Purchased Energy was as follows. - ----------------------------------------------------------------- 1994 1993 1992 - ----------------------------------------------------------------- (Millions of Kilowatt-hours) Net system generation 19,320 19,145 18,274 ====== ====== ====== Purchased energy 8,356 8,448 8,251 ====== ====== ====== - ----------------------------------------------------------------- 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 costs 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 6 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. Fuel expense in 1992 primarily reflects a decrease in net generation and increased purchases of low-cost economy energy from PJM. 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) 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 1992 82.9 12.6 4.5 1.72 2.50 2.32 1.85 - ----------------------------------------------------------------- The increase of approximately 3% in each of the past two years in the system average unit fuel cost 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 actual percent of gas contribution in 1994 to the fuel mix 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 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 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" above 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. 7 The capacity purchase payments referred to in the table above include capacity costs incurred under agreements with Ohio Edison and Southern Maryland Electric Cooperative, Inc. (SMECO), which compare favorably with other long-term capacity and energy alternatives. 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, effective June 1, 1994 through May 31, 1995, the Company is purchasing 147 megawatts of capacity from Pennsylvania Power and Light Company at a total cost of $3 million. The Company has a purchase agreement with SMECO, through 2015, for 84 megawatts of capacity supplied by a combustion turbine installed and owned by SMECO at the Company's Chalk Point Generating Station. The Company is responsible for all costs associated with operating and maintaining the facility. The capacity payment to SMECO is $462,000 per month. Other Operation and Maintenance Expenses - ---------------------------------------- Other operation and maintenance expenses totaled $298.7 million for 1994. These expenses decreased by $2.8 million (.9%) in 1994 and increased by $6.2 million (2.1%) and $8.1 million (2.8%) in 1993 and 1992, respectively. The relative stability in other operation and maintenance expense was achieved through the Company's budget and cost control disciplines, which over the past three years, have resulted in an 6% decline in the number of Company employees, and other programs to curb increases in expenses. In September 1994, to further reduce future costs and staffing levels, the Company announced a Voluntary Severance Program (VSP). As an incentive to voluntarily sever employment no later than the first quarter of 1995, the VSP offered a severance payment to any full-time employee with five or more years of service with the Company, based on two weeks of pay for each year of service, not to exceed 52 weeks of pay. Approximately 340 of the Company's employees will participate in the VSP. During January 1995, approximately $7.4 million in severance costs was expensed. For 1994 and 1993, respectively, other operation expense included $8.7 million and $9.3 million for the accrual of postretirement expenses other than pensions, pursuant to Statement of Financial Accounting Standards (SFAS) No. 106. See the discussion included in Note (3) of the Notes to Consolidated Financial Statements, Pensions and Other Postretirement and Postemployment Benefits, for additional information. 8 Depreciation and Amortization Expense, Income Taxes and Other Taxes - ------------------------------------------------------- Depreciation and amortization expense increased by $16.4 million (10%), $13.8 million (9.2%) and $15.4 million (11.5%) in 1994, 1993 and 1992, respectively, due to additional investment in property and plant and amortization of increased amounts of conservation program costs. The increase in income taxes in 1994 reflects an increase in taxable operating income. The 1993 increase in income taxes reflects the higher federal income tax rate which became effective in 1993 and higher taxable income. Income taxes in 1992 reflects lower taxable income. Other taxes increased by $4.8 million (2.4%), $7.1 million (3.6%) and $27.7 million (16.6%) in 1994, 1993 and 1992, respectively. The increases reflect changes in the levels of operating revenue and plant investment upon which taxes are based. The substantial 1992 increase resulted from increases in gross receipts and fuel and energy tax rates. Other Income, Net Utility Interest Charges and Allowance for Funds Used During Construction - -------------------------------------------------------- Other income reflects the net earnings from the Company's nonutility subsidiary of $19.1 million in 1994, $25.1 million in 1993 and $28.2 million in 1992. 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 in 1994 reflects a total after tax reduction of approximately $4.1 million in connection with District of Columbia Public Service Commission decisions in Formal Case No. 929. This includes 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. See Base Rate Proceedings, District of Columbia, for additional information. In addition, other income reflects accrued capital cost recovery factor (CCRF) amounts in "Other, net" of $10.2 million, $8 million and $2.9 million in 1994, 1993 and 1992, respectively. CCRF is a mechanism which enables the Company to earn a return on certain costs, principally unamortized DSM costs, which are not in rate base. In general, CCRF is earned only on costs specifically allowed by the Company's regulators with provision for cost recovery on a jurisdictional basis. "Other, net" also includes $2.8 million in 1993 from the adoption of SFAS No. 109. See note (4) of the Notes to Consolidated Financial Statements, Income Taxes, for additional information. 9 Net utility interest charges were relatively stable during the three-year period 1992 through 1994, 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 8.26% at the beginning of 1992 to 7.56% at the end of 1994. Allowance For Funds Used During Construction (AFUDC) credits, which decreased during the period 1992 through 1994, relate to portions of the Company's Construction Work In Progress investment. See the Construction and Capacity Additions discussion below. CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- The Company's total investment in property and plant, at original cost, was $5.9 billion at year-end 1994. Investment in property and plant construction, net of AFUDC, was $926.1 million for the period 1992 through 1994. Internally generated cash from utility operations, after dividends, totaled $268.4 million for the period 1992 through 1994. Sales of First Mortgage Bonds, Medium-Term Notes, Convertible Debentures, Serial Preferred Stock and Common Stock during the period 1992 through 1994 provided a total of $1.3 billion. During the years 1992 through 1994, the Company retired $916.7 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 1995 through 1997, capital resources of $233.5 million ($45.4 million in 1995) 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 $758 million is expected to be available from depreciation and amortization charges and income tax deferrals over the three-year period of which approximately $244 million is the 1995 portion. During 1994, the Company sold $80.8 million principal amount of First Mortgage Bonds, $225 million principal amount of Medium- Term Notes and $9.3 million of Common Stock. Proceeds, together with proceeds from a sale and leaseback agreement discussed below, were applied to meet construction requirements of $298.1 million, scheduled debt maturities, sinking fund requirements and the refinancing of higher cost debt totaling $144.4 million and to reduce short-term borrowings by $105 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. 10 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, 1994 was $123.7 million, compared with $114 million and $131.9 million at December 31, 1993 and 1992, 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 at December 31, 1994. The lease requires semi-annual payments of $7.6 million over a 25-year period. This lease has been treated as an operating lease for ratemaking purposes. Dividends on preferred stock were $16.4 million in 1994, $16.3 million in 1993 and $14.4 million in 1992. The embedded cost of preferred stock was 6.37% at December 31, 1991, and 6.53% at December 31, 1994. The Company's capitalization ratios (excluding nonutility subsidiary debt), at December 31, 1994, are presented below. - ----------------------------------------------------------------- Excluding Including Amounts Due Amounts Due In One Year In One Year - ----------------------------------------------------------------- Long-term debt 43.7% 41.2% Redeemable serial preferred stock 3.6 3.4 Serial preferred stock 3.2 3.0 Common equity 49.5 46.8 Short-term debt and amounts due in one year - 5.6 ----- ----- Total capitalization 100.0% 100.0% ===== ===== - ----------------------------------------------------------------- In September 1994, the Company filed for a 5.3% increase in the Maryland fuel rate, which became effective, subject to refund, on November 1, 1994. The initial filing also included an adjustment for a deferred fuel amortization charge to recover over a twelve month period approximately $28.5 million of previously unrecovered fuel costs incurred through July 31, 1994. During the case, which is still pending, the Company updated the proposed deferred fuel amortization, pursuant to a recommendation of the Staff of the Maryland Public Service Commission, to 11 reflect a reduction in the unrecovered amount at October 31, 1994 to $21.1 million. A final order is expected during the first quarter of 1995. Based on results for the period ended November 30, 1994, the Company filed for a fuel rate reduction in Maryland of 5.3%. Year-end 1994 outstanding utility short-term indebtedness totaled $189.6 million compared with $294.6 million and $61.6 million at the end of 1993 and 1992, respectively. At year-end 1994, the formula adopted by the Securities and Exchange Commission would have permitted the Company to issue, without registration, a total of $448 million in commercial promissory notes. The Company maintains a minimum 100% line of credit back-up for its outstanding commercial promissory notes, which was unused during 1994, 1993 and 1992. 1994 Least-Cost Resource Plan - ----------------------------- The Company's 1994 energy plan, which was filed with regulators in June 1994, is an integrated least-cost resource plan. As part of the 1994 planning process, the Company has reassessed each of its existing conservation programs. To reduce the near-term upward pressure on prices and total customer bills, the Company proposes to limit its current offering of DSM programs to those with the strongest cost benefit results and has reduced previously planned five-year conservation expenditures by approximately $120 million. Conservation - ------------ The Company's conservation and energy use management programs are designed to curb growth in demand in order to defer the need for construction of additional generating capacity and to cost- effectively increase the efficiency of energy use. During 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 addition, in November 1994 the Company temporarily suspended approval of additional applications for its Custom Rebate Program. By narrowing its conservation offerings, the Company expects to be able to continue to encourage its customers to use energy efficiently without significantly increasing electricity prices. The Company expects approximately 80% of the previously estimated benefits from conservation for approximately 45% of estimated cost. 12 For residential customers the Company continues to offer rebates for high efficiency heating and air conditioning equipment. These rebates are paid directly to customers when customers buy equipment which significantly exceeds the efficiency of average available equipment. In 1995, the Company expects to resume operation of its highly successful Custom Rebate Program for commercial customers. This program pays rebates to customers who install energy efficient lighting, motors, heating and cooling systems and other measures. The Company also continues to operate the New Building Design Program, which offers cash incentives as well as technical assistance to developers and designers who incorporate energy efficient designs and equipment in new commercial construction. During 1994, the Company invested almost $90 million in energy conservation programs. The Company recovers the costs of its conservation programs in its Maryland jurisdiction through a rate surcharge which amortizes costs over a five year 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 $5 million in 1994 based on its 1993 performance. At the end of 1994 the conservation surcharge in Maryland was $.00338 per kilowatt hour. In the District of Columbia, conservation costs are amortized over 10 years with an accrued return on unamortized costs. To date, costs have been considered in base rate cases. In March 1994, the District of Columbia Public Service Commission denied cost recovery for 25% of the test year cost of operating jurisdictional programs between rate case test years. The disallowed costs totaled $2.2 million on an after tax basis. In response to the Company's request for reconsideration, the Commission directed that the Company's 1994 Least Cost Plan filing include a proposed mechanism for rate recognition of costs between base rate cases. The Company has appealed the disallowance of DSM costs to the District of Columbia Court of Appeals on the basis of the absence of record evidence supporting this action and expects to receive an order on appeal in the second quarter of 1995. In 1994, approximately 151,000 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. 13 It is estimated that peak load reductions of approximately 525 megawatts have been achieved to date from conservation and energy use management programs and that additional peak load reductions of approximately 380 megawatts will be achieved in the next five years. The Company also estimates that in 1994 energy savings of more than 760 million kilowatt-hours have been realized through operation of its conservation and energy use management programs. During the next five years, the Company plans to expend an estimated $370 million ($86 million in 1995) to encourage the efficient use of electric energy and to reduce the need to build new generating facilities. Construction and Generating Capacity - ------------------------------------ Construction expenditures, excluding AFUDC, are projected to total $1.1 billion for the five-year period 1995 through 1999, which includes $165 million of estimated Clean Air Act expenditures. In 1995, construction expenditures are projected to total $215 million, which includes $33 million of estimated Clean Air Act expenditures. Making use of the flexibilities in its long-term construction plan, the Company in 1994 reduced projected expenditures for the five years 1995 through 1999 by $190 million from amounts previously planned. This reduction followed a $365 million reduction in 1993. The construction reductions and deferrals are associated with lower rates of projected growth in usage of electricity resulting in large part from implementing economical conservation programs. The Company plans to finance its construction program primarily through funds provided by operations. A 40-megawatt resource recovery facility with which the Company has a contract is now under construction in Montgomery County, Maryland. 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. This project has received a certificate of convenience and necessity from the Maryland Public Service Commission. These nonutility generation projects are expected to begin operating in 1995 and 1996, respectively. The Company currently 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. Completion of the first combined-cycle unit at its Station H facility in Dickerson, Maryland, is currently scheduled for 2004. This will add a steam cycle to the two combustion turbine units, one of which was installed in 1992 and one of which was installed in 1993. 14 CLEAN AIR ACT - ------------- The Company has developed cost-effective plans for complying with the Clean Air Act (CAA) which requires the reduction of sulfur dioxide and nitrogen oxides emissions in two phases to achieve prescribed standards. Installation of scrubbers is not contemplated for the Company's wholly owned plants. Both the District of Columbia and Maryland commissions have approved the Company's plans for meeting Phase I requirements including cost recovery of investment and inclusion of emission allowance expenses in the Company's fuel adjustment clause. The Company anticipates CAA related capital expenditures totaling $165 million over the next five years. The plans call for replacement of boiler burner equipment for nitrogen oxides emissions control, the use of lower-sulfur fuel and cofiring with natural gas at selected baseload plants. The CAA allows companies to achieve required emission levels by using a market-based emission allowance trading system. If economical, emission allowances may be purchased in lieu of burning lower-sulfur fuel. During 1994, the Company entered into an agreement with Emissions Exchange Corporation (EX) to exchange emission allowances. The Company delivered to EX 25,000 allowances with vintage dates of 1999 or earlier in exchange for receiving 30,000 allowances with vintage dates of 2004 or earlier in equal installments in each of the years 2000 through 2004. This agreement allows the Company to enter the CAA Phase II with a reserve bank of allowances by trading allowances not currently required for a greater number of future allowances, avoiding price risks associated with selling excess Phase I and purchasing Phase II allowances. The Company owns a 9.72% undivided interest in the Conemaugh Generating Station located in western Pennsylvania. As a result of installing flue gas scrubbing equipment to meet Phase I requirements of the CAA, this station will receive additional allowances. The Company's share of these "bonus" allowances may be used to reduce the need for lower-sulfur fuel at its other plants. See the discussion included in Note (6) of the Notes to Consolidated Financial Statements, Jointly Owned Generating Facilities, for additional information. 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. Possible changes in industry 15 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, for purchased capacity in the District of Columbia and emission allowance costs in both retail jurisdictions. Annual base rate increases and decreases which became effective during the period 1992 through 1994 are shown below. - ----------------------------------------------------------------- District of Year Total Maryland Columbia Wholesale - ----------------------------------------------------------------- (Millions of Dollars) 1994 $ 29.3 $ - $26.7 $2.6 1993 38.1 34.3 - 3.8 1992 51.2 18.0 30.4 2.8 ------ ----- ----- ---- $118.6 $52.3 $57.1 $9.2 ====== ===== ===== ==== - ----------------------------------------------------------------- Maryland - -------- In October 1993, pursuant to a settlement agreement, the Commission authorized a $27 million, or 3%, increase in base rate revenue effective November 1, 1993. The settlement included a new system composite depreciation rate of approximately 3.1%, up from the 3% rate previously in effect. In connection with the settlement agreement, no determination was made with respect to rate of 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. District of Columbia - -------------------- In its pending base rate proceeding, the Company is currently seeking a $60.6 million, or 8.2%, increase in base rate revenue, based upon a 1994 calendar year test period and a return of 9.92% on average rate base, including a 12.75% return on common stock equity. This case was filed on September 30, 1994, requesting a $67 million, or 9%, increase in base rate revenue. The Company updated its initial cost of service data filing to reduce the request to $60.6 million to reflect subsequent events which included the sale and leaseback of the Control Center Replacement project, a reduction in the 1995 District of Columbia income tax rate, an approved traffic signal maintenance deregulation 16 agreement with the District of Columbia and an increase in the FICA tax wage base. In accordance with Commission directives, the Company has included conservation program expenditures subsequent to June 1993 in the proposed Environmental Cost Recovery Rider in its pending Least-Cost Planning proceeding filed in June 1994. It is expected that both proceedings will be concluded by mid-1995. On January 17, 1995, the Commission Staff filed testimony recommending a $37.1 million rate increase. In May 1994, the Commission ruled on the application for reconsideration of its March 1994 rate order in Formal Case No. 929. The Commission's original order authorized the Company to increase its base rates by a total of $25.4 million in two steps: an increase of $23.2 million effective March 16, 1994 and an increase of $2.2 million effective June 5, 1994. The order on reconsideration authorized an additional "step 2" base rate increase of $1.3 million resulting in a total base rate increase of $26.7 million. Of the "step 2" increase, $3 million was contingent on the June 1, 1994 in-service date of the final segment of a 500 kilovolt transmission line which provides links in the transmission systems of the Company, Baltimore Gas and Electric Company and Virginia Power. This transmission line segment was placed in service prior to June 1, 1994. The authorized rates are based on a 9.05% rate of return on average rate base, including an 11% return on common stock equity. Prior to the order, the Company had filed updated cost of service data which demonstrated a need for $55.4 million increase in District of Columbia base rate revenue, based upon the requested return of 9.46% on average rate base including an 11.8% return on common stock equity. The Commission's rate increase order approved the Company's proposal for including future changes in purchased capacity costs in fuel adjustment billings. In addition, the Commission reversed its longstanding practice of including Electric Plant Held for Future Use in rate base. The Commission also authorized an accounting change for postretirement benefit costs consistent with Statement of Financial Accounting Standards (SFAS) No. 106 entitled "Employers' Accounting for Postretirement Benefits Other Than Pensions" and adopted a three year phase-in approach for inclusion of these increased costs in the Company's rates. In June 1994, the Company established a regulatory asset for the increase in postretirement benefit costs of $.6 million on an after tax basis which will be amortized over a three year period. The initial order also reduced the Company's revenue requirement to reflect 20% of the cumulative effect of a 1992 accounting change related to unbilled revenue applicable to the District of Columbia. The Commission's initial decision to adopt an unbilled revenue adjustment, supplemented by its subsequent decisions in response to the Company's application for reconsideration and motion for clarification, has required the 17 Company to establish in June 1994 a regulatory liability of $2.5 million on an after tax basis which will be amortized in 1995 and 1996. The Commission's initial decision, rejected the Company's proposal to provide rate recognition of DSM costs through a billing surcharge and consistent with prior decisions, included $5.3 million in base rates to recognize DSM program costs without provision for lost revenue between rate cases. In addition, the initial decision and subsequent decisions in response to the Company's application for reconsideration and motion for clarification, disallowed the recovery of 25% of test period DSM program expenditures which required the Company to write off $2.2 million on an after tax basis in June 1994. In its order on reconsideration, the Commission stated that in the future the appropriate forum for consideration for DSM cost recovery would be the Company's least-cost resource planning cases, which the Company files on a two-year cycle. Under this new process, DSM approval and cost recovery will be linked together in the same proceeding. Subsequent to June 1993, the Company has expended through December 31, 1994, approximately $56 million on conservation in the District of Columbia. The Company requested a surcharge mechanism for billing unamortized DSM costs in its June 1994 Least Cost Planning Case filing. In July 1994, the Company filed a Petition for Review with the District of Columbia Court of Appeals related to the Commission's decisions in Formal Case No. 929 to disallow the recovery of 25% of test period DSM program expenditures and to reject an adjustment to reflect increases in employee benefit costs. The Company expects to receive an order on appeal in the second quarter of 1995. Wholesale - --------- The Company has a 10-year full service power supply contract with 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. The rates were increased by $2.6 million and $3.8 million effective January 1, 1994 and 1993, respectively. A rate increase of $4.2 million is scheduled to become effective January 1, 1996. 18 THE COVE POINT JOINT VENTURE - ---------------------------- Subsidiaries of the Company and the Columbia Gas System, Inc., have formed a 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 in exchange for an equity interest in the Partnership, and the Company's subsidiaries agreed to invest $25 million in the form of equity and debt. This investment will be used by the Partnership to construct a new liquefaction unit and to recommission certain existing facilities at the terminal that will be used in the peaking service discussed below. At December 31, 1994, the Company's subsidiaries have invested $10 million in the Partnership. In November 1993, the Partnership filed a request with the Federal Energy Regulatory Commission (FERC) for approval of proposed natural gas peak-shaving services to local gas distribution companies and other natural gas users beginning with the winter heating season of 1995-96. With the recent restructuring of the natural gas industry under FERC Order 636, this price-competitive service will provide supply security and operating flexibility to local distribution companies in meeting their customers' service obligations. On November 30, 1994, the Partnership received a final order from the FERC granting approval of the project on the basis of cost-of-service rates. The Partnership accepted the FERC certificate during December 1994, and has begun construction and recommissioning activities. The Partnership anticipates the new plant and recommissioned facilities will be available for commercial operation in the fall of 1995. 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 Cove Point pipeline is the sole means of delivering natural gas to southern Maryland where Chalk Point is located. The Company has expanded Chalk Point's fuel flexibility to burn increased amounts of gas to comply with the CAA and minimize customer costs. 19 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. 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 recoverable through future rates, unamortized conservation costs and unamortized debt reacquisition costs. NEW ACCOUNTING STANDARDS - ------------------------ Effective January 1, 1994, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 112 entitled "Employers' Accounting for Postemployment Benefits" and SFAS No. 115 entitled "Accounting for Certain Investments in Debt and Equity Securities." See the discussions included in Notes (3) and (15) of the Notes to Consolidated Financial Statements, Pensions and Other Postretirement Benefits and Selected Nonutility Subsidiary Financial Information, respectively, for additional information. 20 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 1994, the Company was participating in environmental assessments and cleanups under these laws at two 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. NONUTILITY SUBSIDIARY - --------------------- RESULTS OF OPERATIONS - --------------------- PCI's net earnings totaled $19.1 million in 1994, compared with $25.1 million in 1993 and $28.2 million in 1992. In 1994, PCI contributed $.16 per share to PEPCO's consolidated earnings of $1.79 per share. PCI contributed $.22, and $.25 per share, respectively, to PEPCO's 1993 and 1992 consolidated earnings per share. Earnings for the year 1994 were lower than 1993 primarily as a result of the 1993 completion of a transaction whereby PCI contributed aircraft, subject to direct finance leases, to a majority owned partnership. As a result of this transaction, PCI's obligation for previously accrued deferred taxes was reduced, resulting in after tax earnings of $21.3 million, after provision for all costs of the transaction. The excess deferred taxes were recognized in 1993 as a reduction in income tax expense. During 1994, modifications to this 1993 transaction resulted in additional after tax earnings of $10 million. Lower rent revenue and increased operating and maintenance expenses for certain aircraft also contributed to the decrease in PCI's net earnings from 1993 to 1994. At year-end 1994, a portion ($263 million carrying value) of PCI's aircraft leasing portfolio consisted of equipment not on lease (four L-1011 21 aircraft returned by Trans World Airlines (TWA) when leases expired in November 1994) and equipment on short-term, and in some cases, usage-based operating leases with monthly rentals and maintenance payments dependent upon hours used. Under these leases, PCI is responsible for future operating and maintenance expenses exceeding amounts provided therefor by lessees and, during 1994, PCI provided net charges of $8.3 million (before tax) against earnings to establish reserves against such future estimated expenses. Most of the usage-based and short-term leases include provisions for early termination by PCI if more favorable transactions become available. In January 1995, because of the lessee's inability to make timely rental payments and to satisfy other lease obligations, Fortunair Canada returned one B747 aircraft previously under short-term lease. PCI is continuing to seek new leases with more favorable terms or to sell the equipment on satisfactory terms. All rental payments due under equipment leases are current. Continental Airlines (Continental) has announced that it intends to seek the termination of certain A-300 aircraft leases and, effective February 1, 1995, the reduction of rental payments due under certain leases of other widebody aircraft. Pending discussions with lessors, Continental has indicated that it will not be making payments to such lessors as required by the terms of its contracts. Continental has approached PCI to request discussions regarding the return of one A-300 aircraft and the renegotiation of certain other leases of widebody aircraft. Continental has indicated that payments under these leases could include debt securities convertible into equity in lieu of full cash payments. PCI has informed Continental that it expects all lease obligations to be satisfied in full. There can be no assurance that PCI will be able to obtain new leases, sell or otherwise dispose of aircraft on satisfactory terms, following scheduled or unscheduled lease terminations. 22 PCI's aircraft portfolio at December 31, 1994 is summarized below. - ----------------------------------------------------------------- Type of Aircraft Year of Lease Type (a) Lessee Quantity Manufacture - ----------------------------------------------------------------- Operating B747-200 United Airlines 2 1978 Continental Airlines 1 1972 Air Club 1 1976 Fortunair (c) 1 1977 B747-200F Atlas Air 1 1976 DC-10-30 Continental Airlines (b) 5 1973(4), 1974 L1011-50 ING 2 1974 TWA 1 1975 L1011-100 None 4 1974, 1975(3) A300-B4 Continental Airlines 1 1979 F28-4000 US Air 2 1979, 1980 Direct Finance DC-10-30 Continental Airlines 1 1979 MD-82 Continental Airlines (b) 3 1982, 1987(2) B737-300 United Airlines (b) 4 1988 Leveraged B747-300 KLM (b) 1 1984 Singapore Airlines (b) 1 1985 B757-200 Northwest Airlines 1 1986 MD-11F Federal Express 1 1993 - ----------------------------------------------------------------- (a) Includes aircraft in which PCI has a greater than 10% ownership interest. Not included in PCI's balance sheet at December 31, 1994 are two DC-10-30 aircraft on operating lease to PCI. (b) PCI owns a partial interest in certain of these aircraft. (c) Aircraft returned in January 1995. The aircraft leasing business is highly competitive in all of its phases, including the re-leasing and disposition of aircraft. The performance of PCI's aircraft leasing business is dependent upon aircraft market conditions including, among other things, the terms upon which aircraft can be sold or leased, the value of the equipment in the leasing portfolio and the creditworthiness of the lessees of PCI's aircraft which include both domestic and foreign commercial airlines, charter, air cargo 23 and express delivery operators. As discussed above, rental income from the lease of aircraft equipment on short-term or usage-based leases, as well as the market value of such aircraft equipment, has been affected adversely by the lengthy adverse economic cycle and market conditions in the airline industry. There can be no assurance regarding the timing and degree of recovery from these conditions and, therefore, no assurance that PCI will be able to obtain new leases, sell, or otherwise dispose of aircraft on satisfactory terms, following scheduled or unscheduled lease terminations. PCI generates income primarily from its leasing activities and securities investments. Revenue from leasing activities, which includes rental income, gains on asset sales, interest income and fees totaled $111.3 million in 1994 compared with $114.2 million and $122.1 million in 1993 and 1992, respectively. The decrease in 1994 income from leasing activities as compared with 1993 was primarily due to 1993 sales of aircraft that resulted in pre-tax gains of $7.3 million. PCI's marketable securities portfolio contributed pre-tax income of $35.1 million in 1994 compared with $38.4 million and $37.1 million in 1993 and 1992, respectively, which results included net realized gains of $.8 million in 1994 compared with $7 million and $7.5 million in 1993 and 1992, respectively. Income from other activities increased during 1994 over 1993 primarily because 1993 income was reduced by a $13.5 million pre- tax writedown related to the termination of obligations with respect to a real estate limited partnership interest. Expenses, before income taxes, which include interest, depreciation and operating and administrative and general expenses totaled $150.6 million, $159.3 million and $130.5 million for the years ended December 31, 1994, 1993 and 1992, respectively. Of these expenses, interest was the largest single component, amounting to $84.8 million, $77.9 million and $86.2 million in 1994, 1993 and 1992, respectively. Depreciation and operating expenses were $55.6 million in 1994 as compared to $66.8 million in 1993 and $34.6 million in 1992. The decrease in 1994 as compared to 1993 is primarily the result of costs related to the 1993 aircraft partnership transaction. The decrease in depreciation and operating expense was partially offset by increased operating expenses incurred for aircraft not under lease or under usage based leases. PCI had an income tax credit in 1994 of $22.7 million, compared to $45.1 million in 1993 and an expense of $2.5 million in 1992. The decrease in the income tax credit from 1993 to 1994 is primarily the result of the 1993 aircraft partnership transaction referred to above. 24 CAPITAL RESOURCES AND LIQUIDITY - ------------------------------- Investments in leased equipment of $72.1 million in 1994 included $60 million for a one-third undivided interest in a recently- constructed 650 megawatt (gross) baseload, coal and gas fired power plant located in the Netherlands which was purchased and leased back under a long term leveraged lease to a Dutch electric utility. The remaining investment was for aircraft engine purchases and the refurbishment and modification of existing aircraft. Investments of $32.4 million in 1993 reflect the purchase of a new MD-11 aircraft which was placed on long-term leveraged lease at the same time older equipment under lease by the same carrier was sold for proceeds of $108.1 million and a pre-tax gain of $6.2 million and the refurbishment and modification of existing aircraft. At the end of 1994, PCI had no commitments for the purchase of additional aircraft or other equipment leasing assets. PCI's outstanding short-term debt totaled $48.4 million at December 31, 1994, a decrease of $77.8 million from the $126.2 million outstanding at December 31, 1993. During 1994, PCI issued $286.7 million in long-term debt, including non-recourse debt, and debt repayments totaled $173.9 million. At December 31, 1994, PCI had $128.3 million available under its Medium-Term Note Program and $320 million of unused short-term bank credit lines. PCI paid PEPCO a $15 million dividend in January 1994 and, in January 1995, declared a $9 million dividend payable to PEPCO at the end of January, resulting in cumulative dividends of $100 million paid since PCI's inception. PCI remains adequately capitalized to support future business plans, which are designed to supplement utility earnings and build long-term shareholder value. 25 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. 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. As discussed in Notes 1 and 3 of the Notes to Consolidated Financial Statements, respectively, the Company changed its methods of accounting for income taxes and other postretirement benefits in 1993. As also discussed in Note 1, the Company changed its method of accounting for unbilled revenue in 1992. /s/ Price Waterhouse LLP Price Waterhouse LLP Washington, D.C. January 26, 1995 26 Consolidated Statements of Earnings Potomac Electric Power Company and Subsidiaries
- -------------------------------------------------------------------------------------------------- For the year ended December 31, 1994 1993 1992 - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) Revenue (Note 2) Operating revenue $1,790,600 $1,702,442 $1,562,167 Interchange deliveries 32,474 22,763 39,391 ---------- ---------- ---------- Total Revenue 1,823,074 1,725,205 1,601,558 ---------- ---------- ---------- Operating Expenses Fuel 392,730 354,282 345,549 Purchased energy 173,384 173,456 166,601 ---------- ---------- ---------- Fuel and purchased energy 566,114 527,738 512,150 Capacity purchase payments (Note 13) 127,822 96,288 95,481 Other operation 206,106 207,814 204,481 Maintenance 92,614 93,668 90,756 Depreciation and amortization 179,986 163,607 149,785 Income taxes (Note 4) 119,859 110,176 75,272 Other taxes (Note 5) 206,080 201,252 194,180 ---------- ---------- ---------- Total Operating Expenses 1,498,581 1,400,543 1,322,105 ---------- ---------- ---------- Operating Income 324,493 324,662 279,453 ---------- ---------- ---------- Other Income Nonutility subsidiary (Note 15) Income 147,006 139,341 161,154 Expenses, including interest and income taxes (127,918) (114,240) (132,993) ---------- ---------- ---------- Net earnings from nonutility subsidiary 19,088 25,101 28,161 Allowance for other funds used during construction 9,123 13,242 16,089 Other, net 4,046 10,221 1,506 ---------- ---------- ---------- Total Other Income 32,257 48,564 45,756 ---------- ---------- ---------- Income Before Utility Interest Charges 356,750 373,226 325,209 ---------- ---------- ---------- Utility Interest Charges Interest on debt 139,210 141,393 138,097 Allowance for borrowed funds used during construction (9,622) (9,746) (13,648) ---------- ---------- ---------- Net Utility Interest Charges 129,588 131,647 124,449 ---------- ---------- ---------- Income Before Cumulative Effect of Accounting Change 227,162 241,579 200,760 Cumulative Effect of Accounting Change for Unbilled Revenue (Net of Income Taxes of $9,458) (Note 1) - - 16,022 ---------- ---------- ---------- Net Income 227,162 241,579 216,782 Dividends on Preferred Stock 16,437 16,255 14,392 ---------- ---------- ---------- Earnings for Common Stock $ 210,725 $ 225,324 $ 202,390 ========== ========== ========== Average Common Shares Outstanding (000s) 118,006 115,640 112,390 Earnings Per Common Share Before cumulative effect of accounting change $1.79 $1.95 $1.66 Cumulative effect of accounting change for unbilled revenue - - .14 ----- ----- ----- Total $1.79 $1.95 $1.80 ===== ===== ===== Cash Dividends Per Common Share $1.66 $1.64 $1.60 No material dilution would occur if all of the convertible preferred stock and debentures were converted into common stock. 27
Consolidated Balance Sheets Potomac Electric Power Company and Subsidiaries
- --------------------------------------------------------------------------------------------- December 31, Assets 1994 1993 - --------------------------------------------------------------------------------------------- (Thousands of Dollars) Property and Plant - at original cost (Notes 6 and 10) Electric plant in service $ 5,765,210 $ 5,252,736 Construction work in progress 147,224 373,665 Electric plant held for future use 18,041 33,644 Nonoperating property 7,556 5,096 ----------- ----------- 5,938,031 5,665,141 Accumulated depreciation (1,639,771) (1,533,999) ----------- ----------- Net Property and Plant 4,298,260 4,131,142 ----------- ----------- Current Assets Cash and cash equivalents 7,198 7,439 Customer accounts receivable, less allowance for uncollectible accounts of $2,432 and $2,748 107,351 100,973 Other accounts receivable, less allowance for uncollectible accounts of $300 57,128 53,454 Accrued unbilled revenue (Note 1) 67,543 71,497 Prepaid taxes 34,352 30,531 Other prepaid expenses 10,391 6,053 Material and supplies - at average cost Fuel 73,671 61,973 Construction and maintenance 72,447 70,262 ----------- ----------- Total Current Assets 430,081 402,182 ----------- ----------- Deferred Charges Income taxes recoverable through future rates, net (Note 1) 251,357 233,431 Conservation costs, net 161,204 87,328 Unamortized debt reacquisition costs 56,725 53,868 Other 93,840 92,377 ----------- ----------- Total Deferred Charges 563,126 467,004 ----------- ----------- Nonutility Subsidiary Assets Cash and cash equivalents - 2,625 Marketable securities (Notes 11 and 15) 473,608 466,153 Investment in finance leases (Note 15) 410,327 358,524 Operating lease equipment, net of accumulated depreciation of $116,832 and $85,302 (Note 15) 544,064 565,443 Receivables, less allowance for uncollectible accounts of $5,000 in 1994 76,426 84,726 Other investments 147,313 163,911 Other assets 22,551 23,750 ----------- ----------- Total Nonutility Subsidiary Assets 1,674,289 1,665,132 ----------- ----------- Total Assets $ 6,965,756 $ 6,665,460 =========== =========== 28
- --------------------------------------------------------------------------------------------- December 31, Capitalization and Liabilities 1994 1993 - --------------------------------------------------------------------------------------------- (Thousands of Dollars) Capitalization Common equity (Note 7) Common stock, $1 par value - authorized 200,000,000 shares, issued 118,248,103 and 117,797,652 shares $ 118,248 $ 117,798 Premium on stock and other capital contributions 1,020,689 1,011,778 Capital stock expense (14,163) (13,800) Retained income 830,524 839,433 ----------- ----------- Total Common Equity 1,955,298 1,955,209 Preference stock, cumulative, $25 par value - authorized 8,800,000 shares, no shares issued or outstanding - - Serial preferred stock (Notes 8 and 11) 125,409 125,442 Redeemable serial preferred stock (Notes 9 and 11) 143,563 147,000 Long-term debt (Notes 10 and 11) 1,723,399 1,589,621 ----------- ----------- Total Capitalization 3,947,669 3,817,272 ----------- ----------- Other Non-Current Liabilities Capital lease obligation (Note 13) 136,723 - ----------- ----------- Total Other Non-Current Liabilities 136,723 - ----------- ----------- Current Liabilities Long-term debt and preferred stock redemption due within one year 45,445 17,977 Short-term debt (Note 12) 189,600 294,615 Accounts payable and accrued payroll 117,909 116,526 Capital lease obligation due within one year 15,233 - Taxes accrued 20,509 25,840 Interest accrued 36,840 32,476 Customer deposits 22,563 22,296 Other 84,842 81,337 ----------- ----------- Total Current Liabilities 532,941 591,067 ----------- ----------- Deferred Credits Income taxes (Notes 1 and 4) 848,456 780,723 Investment tax credits (Note 4) 68,256 71,906 Other 31,766 28,916 ----------- ----------- Total Deferred Credits 948,478 881,545 ----------- ----------- Nonutility Subsidiary Liabilities Long-term debt (Notes 10 and 11) 1,140,505 1,027,705 Short-term notes payable (Note 12) 48,400 126,250 Deferred taxes and other (Note 4) 211,040 221,621 ----------- ----------- Total Nonutility Subsidiary Liabilities 1,399,945 1,375,576 ----------- ----------- Commitments and Contingencies (Note 13) Total Capitalization and Liabilities $ 6,965,756 $ 6,665,460 =========== =========== 29
Consolidated Statements of Cash Flows Potomac Electric Power Company and Subsidiaries
- ----------------------------------------------------------------------------------------------------- For the year ended December 31, 1994 1993 1992 - ----------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities Income from utility operations $ 208,074 $ 216,478 $ 188,621 Adjustments to reconcile income to net cash from operating activities: Depreciation and amortization 179,986 163,607 149,785 Deferred income taxes and investment tax credits 44,641 27,711 43,414 Allowance for funds used during construction (18,745) (22,988) (29,737) Changes in materials and supplies (13,883) 44,509 (11,144) Changes in accounts receivable and accrued unbilled revenue (6,098) (35,399) (46,483) Changes in accounts payable 8,257 (441) (5,716) Changes in other current assets and liabilities (11,703) 4,317 6,325 Changes in deferred conservation costs (92,504) (59,639) (26,627) Net other operating activities 5,303 (37,121) 8,078 Nonutility subsidiary: Net earnings 19,088 25,101 28,161 Deferred income taxes 6,386 (32,814) 1,055 Changes in other assets and net other operating activities 47,648 56,897 7,037 --------- --------- --------- Net Cash From Operating Activities 376,450 350,218 312,769 --------- --------- --------- Investing Activities Total investment in property and plant (316,890) (322,951) (357,732) Allowance for funds used during construction 18,745 22,988 29,737 --------- --------- --------- Net investment in property and plant (298,145) (299,963) (327,995) Nonutility subsidiary: Purchase of marketable securities (127,335) (254,213) (266,696) Proceeds from sale or redemption of marketable securities 82,444 194,295 195,752 Investment in leased equipment (72,134) (32,360) (30,811) Proceeds from sale or disposition of leased equipment 1,150 120,529 48,968 Purchase of other investments (7,191) (44,628) (7,143) Proceeds from sale or distribution of other investments 18,429 - 42,513 Investment in promissory notes (542) (1,628) - Proceeds from promissory notes 4,902 3,013 27,411 --------- --------- --------- Net Cash Used by Investing Activities (398,422) (314,955) (318,001) --------- --------- --------- Financing Activities Dividends on common stock (195,755) (189,837) (179,823) Dividends on preferred stock (16,437) (16,255) (14,392) Issuance of common stock 9,285 96,001 80,396 Issuance of preferred stock - - 50,000 Redemption of preferred stock (4,047) (1,500) (890) Issuance of long-term debt 302,999 521,264 277,463 Reacquisition and retirement of long-term debt (144,422) (628,448) (137,387) Proceeds from sale and leaseback of control center system 152,000 - - Short-term debt, net (105,015) 233,015 (25,200) Other financing activities (14,452) (26,199) (5,946) Nonutility subsidiary: Issuance of long-term debt 286,750 363,653 242,637 Repayment of long-term debt (173,950) (247,077) (274,991) Short-term debt, net (77,850) (137,265) (7,390) --------- --------- --------- Net Cash From (Used by) Financing Activities 19,106 (32,648) 4,477 --------- --------- --------- Net (Decrease) Increase In Cash and Cash Equivalents (2,866) 2,615 (755) Cash and Cash Equivalents at Beginning of Year 10,064 7,449 8,204 --------- --------- --------- Cash and Cash Equivalents at End of Year (Note 14) $ 7,198 $ 10,064 $ 7,449 ========= ========= ========= 30
Notes to Consolidated Financial Statements - ------------------------------------------ (1) Summary of Significant Accounting Policies ------------------------------------------ The Company's utility operations are regulated by the Maryland and District of Columbia public service commissions and, as to its wholesale business, 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. In conformity with generally accepted accounting principles, the accounting policies and practices applied by the regulatory commissions in the determination of rates for utility operations are also employed for financial reporting purposes. Certain prior year amounts have been reclassified to conform to the current year presentation. A description of significant accounting policies follows. Principles of Consolidation - --------------------------- The consolidated financial statements combine the financial results of the Company and all majority-owned subsidiaries. The Company's principal subsidiary is Potomac Capital Investment Corporation (PCI). All material intercompany balances and transactions have been eliminated. Total Revenue - ------------- The Company changed its method of revenue recognition effective January 1, 1992, to provide for the accrual of revenue for service rendered but unbilled as of the end of each month. Prior to 1992, revenue was recognized using the meters read method of accounting whereby annual revenue reflected 12 monthly meter readings for each customer. The new method was adopted to provide a better matching of revenue and expenses and to conform with the predominant practice within the utility industry. This change in the method of revenue recognition resulted in an increase in 1992 of approximately $16 million in net income or $.14 per common share. This change in accounting method, which has no significant effect on revenue over a 12-month period, affects the timing of revenue recognition within the year, principally increasing revenue in the second quarter and decreasing revenue in the fourth quarter. 31 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. Leasing Transactions - -------------------- Income from PCI investments in direct finance and leveraged lease transactions, in which PCI is an equity participant, is reported using the financing method. In accordance with the financing method, investments in leased property are recorded as a receivable from the lessee to be recovered through the collection of future rentals. For direct finance leases, unearned income is amortized to income over the lease term at a constant rate of return on the net investment. Income, including investment tax credits on leveraged equipment leases, is recognized over the life of the lease at a level rate of return on the positive net investment. PCI investments in equipment under operating leases are stated at cost less accumulated depreciation. Depreciation is recorded on a straight line basis over the equipment's estimated useful life. Property and Plant - ------------------ The cost of additions to, and replacements or betterments of, retirement units of property and plant is capitalized. Such cost includes material, labor, the capitalization of an Allowance for Funds Used During Construction (AFUDC) and applicable indirect costs, including engineering, supervision, payroll taxes and employee benefits. The original cost of depreciable units of plant retired, together with the cost of removal, net of salvage, is charged to accumulated depreciation. Routine repairs and maintenance are charged to operating expenses as incurred. 32 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 1994 and 1993 and 3% for 1992. Conservation - ------------ In general, the Company accounts for conservation expenditures in connection with its demand side management (DSM) program as a deferred charge, and amortizes the costs over five to ten years. District of Columbia conservation costs receive rate base treatment, with a capital cost recovery factor accrued on the unamortized balance in excess of amounts included in rate base. In Maryland, conservation costs are recovered through a surcharge included in base rates which reflects current year expenditures and lost revenue. 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. In 1992, pursuant to orders from both the Maryland and District of Columbia commissions, the Company commenced the accrual of 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 7.6% in 1994, 8.7% in 1993 and 9.1% in 1992, compounded semiannually. 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. 33 Income Taxes - ------------ Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 109 entitled "Accounting for Income Taxes" which requires the use of an asset and liability approach for financial reporting and accounting for deferred income taxes. Deferred taxes are recorded for all temporary differences based upon currently enacted tax rates. The adoption of SFAS No. 109 increased net income for the twelve months ended December 31, 1993 by $2.8 million which is reflected on the Consolidated Statements of Earnings in "Other, net." Certain provisions of SFAS No. 109 allow regulated enterprises to recognize regulatory assets and liabilities for income taxes to be recovered from or returned to customers in future rates. No valuation allowance for deferred tax assets was required or recorded at December 31, 1994 and 1993. 34 (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 eleven electric utilities which operate on a fully integrated basis. Total revenue for each year was comprised as shown below. - ----------------------------------------------------------------- 1994 1993 1992 ------------------------------------------------- Amount % Amount % Amount % - ----------------------------------------------------------------- (Thousands of Dollars) Residential $ 524,737 29.4 $ 505,173 29.8 $ 432,797 27.8 Commercial 834,323 46.8 791,357 46.6 748,550 48.1 U.S. Government 254,030 14.2 238,192 14.0 229,586 14.8 D.C. Government 56,655 3.2 53,551 3.2 49,815 3.2 Wholesale 113,319 6.4 108,162 6.4 95,350 6.1 ---------- ----- --------- ----- ---------- ----- Sales of electricity 1,783,064 100.0 1,696,435 100.0 1,556,098 100.0 ===== ===== ===== Other electric revenue 7,536 6,007 6,069 ---------- ---------- ---------- Operating revenue 1,790,600 1,702,442 1,562,167 Interchange deliveries 32,474 22,763 39,391 ---------- ---------- ---------- Total Revenue $1,823,074 $1,725,205 $1,601,558 ========== ========== ========== - ----------------------------------------------------------------- Sales of electricity include base rate revenue and fuel rate revenue. Fuel rate revenue was $557.4 million in 1994, $487.9 million in 1993 and $456.4 million in 1992. 35 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. In September 1994, the Company filed for a 5.3% increase in the Maryland fuel rate which became effective, subject to refund, on November 1, 1994. The initial filing also included an adjustment for a deferred fuel amortization charge to recover over a twelve month period approximately $28.5 million of previously unrecovered fuel costs incurred through July 31, 1994. During the case, which is still pending, the Company updated the proposed deferred fuel amortization, pursuant to a recommendation of the Staff of the Maryland Public Service Commission, to reflect a reduction in the unrecovered amount at October 31, 1994 to $21.1 million. A final order is expected during the first quarter of 1995. Based on results for the period ended November 30, 1994, the Company filed for a fuel rate reduction in Maryland of 5.3%. 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. 36 (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. Pension expense included in net income was $14.3 million in 1994, $13.7 million in 1993 and $10.5 million in 1992. The net periodic pension cost was computed as follows. - ----------------------------------------------------------------- 1994 1993 1992 - ----------------------------------------------------------------- (Thousands of Dollars) Service cost-benefits earned $10,800 $10,300 $ 9,100 Interest cost on projected benefit obligation 26,800 25,100 23,500 Actual return on Program assets (4,600) (24,300) (13,400) Differences between actual and expected return on Program assets and net amortization (18,700) 2,600 (8,700) ------- ------- ------- Pension cost $14,300 $13,700 $10,500 ======= ======= ======= - ----------------------------------------------------------------- 37 Program assets are stated at fair value and were comprised of approximately 70% and 68% of cash equivalents and fixed income investments and the balance in equity investments at December 31, 1994 and 1993, respectively. The following table sets forth the Program's funded status and amounts recognized on the Consolidated Balance Sheets. - ----------------------------------------------------------------- 1994 1993 - ----------------------------------------------------------------- (Thousands of Dollars) Actuarial present value of benefit obligations: Program benefits: Vested benefits $(252,300) $(249,600) Nonvested benefits (30,000) (35,300) --------- --------- Accumulated benefit obligation $(282,300) $(284,900) ========= ========= Actuarial present value of projected benefit obligation $(338,600) $(358,600) Program assets at fair value 289,100 282,600 --------- --------- Projected benefit obligation in excess of Program assets (49,500) (76,000) Unrecognized actuarial loss 35,600 58,500 Unrecognized prior service cost 17,600 12,900 Unrecognized net obligation at January 1, 1987, being recognized over 18 years 400 400 --------- --------- Prepaid pension expense/accrued pension (liability) $ 4,100 $ (4,200) ========= ========= - ----------------------------------------------------------------- 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 8.5% and 4.5% in 1994 and 7.75% and 5% in 1993, respectively. The assumed long-term rate of return on Program assets was 9% in 1994 and 1993. 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 38 benefits of these plans if they retire under the provisions of the Company's General Retirement Program with ten years of service or become inactive employees under the Company's disability plans. Effective January 1, 1993, the Company adopted SFAS No. 106, entitled "Employers' Accounting for Postretirement Benefits Other Than Pensions" which requires "accrual basis" instead of "cash basis" accounting for postretirement health care and life insurance. The effect of this change in accounting was to decrease 1993 pre-tax income by $2.2 million. 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 $8.7 million and $9.3 million in 1994 and 1993, respectively. The cost of such benefits, recognized as an operating expense when paid, was $5 million in 1992. The following table sets forth the components of the postretirement expense. - ----------------------------------------------------------------- 1994 1993 - ----------------------------------------------------------------- (Thousands of Dollars) Service cost-benefits attributable to service during the year $ 2,600 $ 2,500 Interest cost on accumulated postretirement benefit obligation 4,200 4,400 Actual loss (return) on Plan assets 200 (400) Amortization of transition obligation 2,500 2,800 Difference between actual and expected return on Plan assets and net amortization (800) - ------- ------- Net postretirement benefit cost $ 8,700 $ 9,300 ======= ======= - ----------------------------------------------------------------- 39 The following table sets forth the accumulated postretirement benefit obligation reconciled to the amounts recognized on the Consolidated Balance Sheets. - ----------------------------------------------------------------- 1994 1993 - ----------------------------------------------------------------- (Thousands of Dollars) Accumulated postretirement benefit obligation to Retirees and dependents $(34,600) $(29,700) Active employees fully eligible (10,600) (10,300) Active employees not fully eligible (14,800) (14,800) -------- -------- Total accumulated postretirement benefit obligation (60,000) (54,800) Plan assets at fair value 4,500 4,300 -------- -------- Accumulated postretirement benefit obligation in excess of Plan assets (55,500) (50,500) Unrecognized transition obligation 45,200 47,700 Unrecognized actuarial loss 11,100 2,800 -------- -------- Prepaid/(accrued) postretirement benefit cost $ 800 $ - ======== ======== - ----------------------------------------------------------------- The Company's SFAS No. 106 obligation at December 31, 1994 and 1993 was based on discount rates of 8.5% and 7.75%, respectively, and weighted average rates of increase in future compensation levels of 4.5% and 5%, respectively. The current health-care cost trend rate is 8% which declines to 5.5% after a five year period. A one percentage point increase in the health- care cost trend rate would increase the Accumulated Postretirement Benefit Obligation by $3.7 million to approximately $63.7 million and the sum of the service cost and interest cost for 1994 by approximately $.5 million. In January 1994 and 1993, the Company funded the 1994 and 1993 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. Assets were comprised of cash equivalents, fixed income investments and equity investments and the assumed return on plan assets was 9% in 1994 and 1993. 40 In July 1993, a new three-year Agreement between the Company and Local 1900 of the International Brotherhood of Electrical Workers was ratified by Union members. As a result of this Agreement, the Company reduced the costs of its postretirement benefits by requiring all eligible employees who retired on or after January 1, 1994, to share in the cost of these benefits. These amendments were reflected in 1993. The Company treats postretirement benefit costs as an operating expense. The Company's Maryland tariff includes the cost of postretirement benefits. In May 1994, the District of Columbia Public Service Commission authorized an accounting change for postretirement benefit costs consistent with SFAS No. 106 and adopted a three-year phase-in approach for inclusion of these increased costs in the Company's rates. Effective January 1, 1994, the Company adopted SFAS No. 112 entitled "Employers' Accounting for Postemployment Benefits" which requires the accrual of the expected cost of providing benefits to former or inactive employees after employment but before retirement. The adoption of this pronouncement did not have a material effect on the Company's consolidated financial statements. 41 (4) Income Taxes ------------ The provision for income taxes charged to continuing operations, reconciliation of consolidated income tax expense and components of consolidated deferred tax liabilities (assets) are set forth below.
Provisions for Income Taxes Charged to Continuing Operations - ------------------------------------------------------------ - --------------------------------------------------------------------------------------------------- 1994 1993 1992 - --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Utility current tax expense Federal $ 63,395 $ 69,007 $ 50,900 State and local 8,612 9,801 7,571 --------- --------- --------- Total utility current tax expense 72,007 78,808 58,471 --------- --------- --------- Utility deferred tax expense Federal 42,070 26,784 26,584 State and local 6,221 5,100 4,682 Investment tax credits (3,650) (3,469) (3,314) --------- --------- --------- Total utility deferred tax expense 44,641 28,415 27,952 --------- --------- --------- Total utility income tax expense 116,648 107,223 86,423 --------- --------- --------- Nonutility subsidiary current tax expense Federal (29,315) (13,022) 1,461 --------- --------- --------- Nonutility subsidiary deferred tax expense Federal 6,758 (31,360) 1,055 State and local (138) (696) - --------- --------- --------- Total nonutility subsidiary deferred tax expense 6,620 (32,056) 1,055 --------- --------- --------- Total nonutility subsidiary income tax expense (22,695) (45,078) 2,516 --------- --------- --------- Total consolidated income tax expense 93,953 62,145 88,939 Income taxes included in other income (25,906) (48,031) 4,209 Income taxes included in cumulative effect of accounting change - - 9,458 --------- --------- --------- Income taxes included in utility operating expenses $ 119,859 $ 110,176 $ 75,272 ========= ========= ========= 42
Reconciliation of Consolidated Income Tax Expense - ------------------------------------------------- - --------------------------------------------------------------------------------------------------- 1994 1993 1992 - --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Income before income taxes (including cumulative effect of accounting change) $ 321,115 $ 303,724 $ 305,721 ========= ========= ========= Utility income tax at federal statutory rate $ 113,653 $ 113,295 $ 93,515 Increases (decreases) resulting from Depreciation 8,022 5,096 4,204 Removal costs (4,086) (4,385) (5,109) Allowance for funds used during construction (2,411) (3,852) (4,854) Other (4,175) (6,477) (5,888) State income taxes, net of federal effect 9,683 9,686 8,213 Tax credits (4,038) (3,873) (3,658) Cumulative effect of tax rate change - (2,267) - --------- --------- --------- Total utility income tax expense 116,648 107,223 86,423 --------- --------- --------- Nonutility subsidiary income tax at federal statutory rate (1,262) (6,992) 10,430 Increases (decreases) resulting from Dividends received deduction (8,487) (7,672) (6,750) Reversal of previously accrued deferred taxes (8,206) (35,904) - Other (4,602) (408) (1,164) State income taxes, net of federal effect (138) (696) - Cumulative effect of tax rate change - 6,594 - --------- --------- --------- Total nonutility subsidiary income tax expense (22,695) (45,078) 2,516 --------- --------- --------- Total consolidated income tax expense 93,953 62,145 88,939 Income taxes included in other income (25,906) (48,031) 4,209 Income taxes included in cumulative effect of accounting change - - 9,458 --------- --------- --------- Income taxes included in utility operating expenses $ 119,859 $ 110,176 $ 75,272 ========= ========= =========
Components of Consolidated Deferred Tax Liabilities (Assets) - ------------------------------------------------------------ At December 31, ---------------------- 1994 1993 ---------------------- (Thousands of Dollars) Utility deferred tax liabilities (assets) Depreciation and other book to tax basis differences $ 723,248 $ 672,625 Rapid amortization of certified pollution control facilities 29,018 31,090 Deferred taxes on amounts to be collected through future rates 95,465 88,787 Property taxes 11,212 10,218 Deferred fuel 177 4,644 Prepayment premium on debt retirement 21,537 11,215 Deferred investment tax credit (25,922) (27,435) Contributions in aid of construction (24,954) (23,951) Other 25,454 21,825 --------- --------- Total utility deferred tax liabilities (net) 855,235 789,018 Current portion of utility deferred tax liabilities (included in Other Current Liabilities) 6,779 8,295 --------- --------- Total utility deferred tax liabilities (net) - non current $ 848,456 $ 780,723 ========= ========= Nonutility subsidiary deferred tax liabilities (assets) Finance leases $ 134,925 130,833 Operating leases 117,782 114,134 Reversal of previously accrued taxes related to partnerships (16,385) (16,969) Alternative minimum tax (77,167) (75,610) Other (24,477) (9,789) --------- --------- Total nonutility subsidiary deferred tax liabilities (net), (included in Deferred taxes and other) $ 134,678 $ 142,599 ========= ========= 43
The Omnibus Budget Reconciliation Act of 1993, which was enacted on August 10, 1993, increased the federal corporate income tax rate from 34% to 35% for the periods beginning after December 31, 1992. 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. 44 (5) Other Taxes ----------- Taxes, other than income taxes, charged to utility operating expenses for each period are shown below. - ---------------------------------------------------------------- 1994 1993 1992 - ---------------------------------------------------------------- (Thousands of Dollars) Gross receipts $ 93,549 $ 88,044 $ 81,266 Property 60,443 58,193 55,965 Payroll 11,063 10,534 10,582 County fuel-energy 30,842 34,614 37,283 Environmental, use and other 10,183 9,867 9,084 -------- -------- -------- $206,080 $201,252 $194,180 ======== ======== ======== - ----------------------------------------------------------------- 45 (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 $81.1 million at December 31, 1994 and $67.1 million at December 31, 1993, includes $9.5 million and $23.4 million of Construction Work in Progress, respectively. The Conemaugh Generating Station is required to comply with certain provisions of the Clean Air Act Amendments of 1990. As of December 31, 1994 nitrogen oxide reduction equipment has been installed on both generating units and flue gas desulfurization equipment has been installed on Unit 1. The Unit 2 flue gas desulfurization equipment is scheduled for completion by December 31, 1995. The Company's share of the construction costs is approximately $38 million. The project, at December 31, 1994, was approximately 85% complete. 46 (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, 1991 111,105,797 $ 111,106 $ 841,583 $ 776,140 Net income before net earnings from nonutility subsidiary - - - 188,621 Nonutility subsidiary: Net earnings - - - 28,161 Marketable equity securities valuation allowance, net of tax - - - 4,067 Dividends: Preferred stock - - - (14,392) Common stock - - - (179,823) Conversion of convertible debentures 2,220 2 58 - Conversion of preferred stock 22,318 22 169 - Gain on acquisition of preferred stock - - 24 - Other capital contributions - - 25 - Sale of common stock through Shareholder Dividend Reinvestment Plan 1,787,724 1,788 42,414 - Issuance of common stock to Employee Savings Plans 378,384 378 9,028 - Sale of common stock through public offerings 1,000,000 1,000 25,788 - ----------- ---------- ---------- ---------- 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 =========== ========== ========== ========== 47
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, 1994, 48,869 shares of common stock were reserved for issuance upon the conversion of convertible preferred stock, 2,771,633 shares for issuance upon the conversion of the 7% convertible debentures, 3,392,500 shares for issuance upon the conversion of the 5% convertible debentures, 2,483,222 shares for issuance under the DRP and 1,299,867 shares for issuance under the Employee Savings Plans. Certain provisions of the Company's corporate charter, relating to preferred and preference stock, would impose restrictions on the payment of dividends under certain circumstances. No portion of retained income was so restricted at December 31, 1994. 48 (8) Serial Preferred Stock ---------------------- The Company has authorized 11,159,434 shares of cumulative $50 par value Serial Preferred Stock. At December 31, 1994 and 1993, there were outstanding 5,379,433 shares and 5,461,038 shares, respectively. The various series of Serial Preferred Stock outstanding (excluding 2,871,251 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 1994 1993 - ----------------------------------------------------------------- (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, 8,182 and 8,838 shares, respectively $50.00 409 442 Auction Series A, 1,000,000 shares $50.00 50,000 50,000 -------- -------- $125,409 $125,442 ======== ======== - ----------------------------------------------------------------- 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, 1994, 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 656 shares in 1994, 948 shares in 1993 and 3,827 shares in 1992. 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 4.833% ($2.4165) for the period December 1, 1994 through February 28, 1995. The average annual dividend rates were 3.55% ($1.775) in 1994 and 2.8% ($1.40) in 1993. 49 (9) Redeemable Serial Preferred Stock --------------------------------- The outstanding series of $50 par value Redeemable Serial Preferred Stock are shown below. - ----------------------------------------------------------------- December 31, 1994 1993 - ----------------------------------------------------------------- (Thousands of Dollars) $3.37 Series of 1987, 871,251 and 952,200 shares, respectively $ 43,563 $ 47,610 $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 -------- -------- 143,563 147,610 Redemption requirement due within one year - (610) -------- -------- $143,563 $147,000 ======== ======== - ---------------------------------------------------------------- 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. 50 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 1999 with respect to the Redeemable Serial Preferred Stock are $1.1 million in 1997 and $1.5 million annually thereafter. 51 (10) Long-Term Debt
Details of long-term debt are shown below. - ------------------------------------------------------------------------------------------------------ Interest December 31, Rate Maturity 1994 1993 - ------------------------------------------------------------------------------------------------------ (Thousands of Dollars) First Mortgage Bonds Fixed Rate Series: 5-1/4% December 1, 1994 $ - $ 15,000 5% December 15, 1995 40,000 40,000 5-5/8% December 31, 1997 16,000 18,000 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% July 1, 2004 - 15,000 6-1/8% July 1, 2007 - 38,300 6-1/2% July 1, 2007 - 20,000 6-1/2% March 15, 2008 78,000 78,000 5-7/8% October 15, 2008 50,000 50,000 6-5/8% January 1, 2009 - 7,500 9-3/4% May 1, 2019 - 43,000 8-5/8% August 15, 2019 59,800 63,000 9% June 1, 2021 100,000 100,000 6% September 1, 2022 30,000 30,000 6-3/8% January 15, 2023 37,000 37,000 7-1/4% July 1, 2023 100,000 100,000 6-7/8% September 1, 2023 100,000 100,000 5-3/8% February 15, 2024 42,500 - 5-3/8% February 15, 2024 38,300 - 6-7/8% October 15, 2024 75,000 75,000 8-1/2% May 15, 2027 75,000 75,000 7-1/2% March 15, 2028 40,000 40,000 Variable Rate Series: Adjustable rate December 1, 2001 50,000 50,000 ---------- ---------- Total First Mortgage Bonds 1,266,600 1,329,800 Convertible Debentures 5% September 1, 2002 115,000 115,000 7% January 15, 2018 68,412 68,834 Medium-Term Notes 6.25% May 28, 1996 25,000 - 6.66% to 6.73% May 1997 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 - 7% January 15, 2024 50,000 - ---------- ---------- Total Utility Long-Term Debt 1,800,012 1,638,634 Net unamortized discount (31,168) (31,646) Current portion (45,445) (17,367) ---------- ---------- Net Utility Long-Term Debt $1,723,399 $1,589,621 ========== ========== Nonutility Subsidiary Long-term Debt Varying rates through 2011 $1,140,505 $1,027,705 ========== ========== 52
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 1994, the Company issued $80.8 million of 5-3/8% First Mortgage Bonds and $225 million of 6-1/4% to 7% Medium-Term Notes with various maturities. A portion of the proceeds from these financings were used to redeem $127 million of higher cost First Mortgage Bonds and to satisfy long-term debt maturities and sinking fund requirements totaling $17 million. 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, 1994, the applicable interest rate is 8.68%. The applicable interest rate was 6.657% at December 1, 1993 and 7.733% at December 1, 1992. The Bonds were nonredeemable prior to December 1, 1994. 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 and sinking fund requirements for the Company's long-term debt outstanding at December 31, 1994 are $45.4 million in 1995, $31 million in 1996, $156 million in 1997, $50 million in 1998 and $45 million in 1999. Nonutility Subsidiary Long-Term Debt - ------------------------------------ Long-term debt at December 31, 1994 consisted of $1.1 billion of recourse debt from institutional lenders maturing at various dates between 1995 and 2003. The interest rates of such borrowings ranged from 4.7% to 10.10%. The weighted average interest rate was 7.47% at December 31, 1994, 7.45% at December 31, 1993 and 8.13% at December 31, 1992. Annual aggregate principal repayments are $260.4 million in 1995, $188.5 million in 1996, $135.5 million in 1997, $177.3 million in 1998, $126.5 million in 1999 and $179.5 million thereafter. 53 Long-term debt also includes $72.7 million of non-recourse debt, $48.7 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 $24 million is related to PCI's majority owned real estate partnerships of which $15.5 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 $8.5 million payable in monthly installments at a fixed rate of interest of 9.66% with final maturity on October 1, 2011. 54 (11) Fair Value of Financial Instruments - ---------------------------------------- The estimated fair values of the Company's financial instruments at December 31, 1994 and 1993 are shown below.
- -------------------------------------------------------------------------------------------- December 31, 1994 1993 - -------------------------------------------------------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value ----------- ----------- ----------- ----------- (Thousands of Dollars) Utility Capitalization and Liabilities Serial preferred stock $ 125,409 $ 102,102 $ 125,442 $ 110,919 Redeemable serial preferred stock 143,563 134,008 147,000 164,115 Long-term debt First Mortgage Bonds 1,208,076 1,093,208 1,297,355 1,354,887 Medium-Term Notes 347,712 324,223 124,435 138,823 Convertible Debentures 167,611 146,098 167,831 177,107 Nonutility Subsidiary Assets Marketable securities $ 473,608 $ 473,608 $ 466,153 $ 473,151 Notes receivable 61,278 58,616 60,688 60,300 Liabilities Long-term debt 1,140,505 1,122,638 1,027,705 1,080,978 - -------------------------------------------------------------------------------------------- 55
The methods and assumptions below were used to estimate, at December 31, 1994 and 1993, 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 and excluding amounts due within one year, was based on quoted market prices or discounted cash flows using current rates of preferred stock with similar terms. The fair value of 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. (12) Short-Term Debt --------------- The Company's short-term financing requirements have been satisfied principally through the sale of commercial promissory notes. The Company maintains a minimum 100% line of credit back-up for its outstanding commercial promissory notes, which was unused during 1994, 1993 and 1992. 56 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 1994, 1993 and 1992. (13) Commitments and Contingencies ----------------------------- 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 $14.9 million in 1994, $13.6 million in 1993 and $12.6 million in 1992. The approximate annual commitments under all operating leases, reduced by rentals to be received under subleases are $13.4 million in 1995, $12.4 million in 1996, $5.8 million in 1997, $5.4 million in 1998, $5.2 million in 1999 and a total of $15.5 million in the years thereafter. During December 1994, the Company entered into a sale (at cost) and leaseback agreement 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 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 at December 31, 1994. 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. 57 Fuel Contracts - -------------- The Company has numerous coal contracts with various expiration dates through 2003 for aggregate annual deliveries of approximately 3.5 million tons. Deliveries under these contracts are expected to provide approximately 58% of the estimated system coal requirements in 1995. Approximately 42% of the estimated system coal requirements in 1995 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, was $12,380 per megawatt through 1993, $18,060 per megawatt effective 1994 through 1998 and $25,620 per megawatt from 1999 through 2005. 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 capacity payment to SMECO is $462,000 per month. Environmental Contingencies - --------------------------- 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 Cases." The Company (and other defendants) were brought into these cases on a theory of premises liability under which plaintiffs argue that the Company was negligent in not providing a safe work environment for employees of its contractors who 58 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 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 (PRPs) completed a removal action at a site in Harmony, West Virginia pursuant to an Administrative Order (AO) issued by the 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. 59 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 participating PRPs, the Company is responsible for 12% of the costs of the RI/FS. Total costs of the RI/FS, including legal fees, are currently estimated to be $5.6 million. The Company has paid $836,000 to date. The report includes a number of possible remedies, the estimated costs of which range from $2 million to $90 million. While a remedy near the lower end of the range is possible, the Company cannot predict what remedy may be acceptable to the EPA. In addition, the Company cannot estimate the total extent of the EPA's administrative and oversight costs. To date, the Company has accrued approximately $1.7 million for its share of this contingency. Litigation - ---------- 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. Other - ----- In September 1994, to further reduce future costs and staffing levels, the Company announced a Voluntary Severance Program (VSP). As an incentive to voluntarily sever employment no later than the first quarter of 1995, the VSP offered a severance payment to any full-time employee with five or more years of service with the Company, based on two weeks of pay for each year of service, not to exceed 52 weeks of pay. Approximately 340 of the Company's employees will participate in the VSP. During January 1995, approximately $7.4 million in severance costs was expensed. Subsidiaries of the Company and the Columbia Gas System, Inc. have formed a joint venture partnership (the Partnership) to own and operate natural gas and storage terminaling facilities at Cove Point, Maryland, and an 87-mile natural gas pipeline that extends from Cove Point to Loudoun County, Virginia. A Company subsidiary has committed to loan the Partnership $15 million to recommission certain existing facilities and for new construction. As of December 31, 1994, the remaining $14.9 million of the loan commitment is yet to be drawn upon by the Partnership. 60 Nonutility Subsidiary - --------------------- At December 31, 1994 a portion ($263 million carrying value) of PCI's aircraft leasing portfolio consisted of equipment not on lease (four L-1011 aircraft returned by TWA when leases expired in November 1994) and equipment on short-term, and in some cases, usage-based operating leases with monthly rentals and maintenance payments dependent upon hours used. Under these leases, PCI is responsible for future operating and maintenance expenses exceeding amounts provided therefor by lessees and, during 1994, PCI provided net charges of $8.3 million (before tax) against earnings to establish reserves against such future estimated expenses. Most of the usage-based and short-term leases include provisions for early termination by PCI if more favorable transactions become available. In January 1995, because of the lessee's inability to make timely rental payments and to satisfy other lease obligations, Fortunair Canada returned one B747 aircraft previously under short-term lease. PCI is continuing to seek new leases with more favorable terms or to sell the equipment on satisfactory terms. All rental payments due under equipment leases are current. Continental Airlines (Continental) has announced that it intends to seek the termination of certain A-300 aircraft leases and, effective February 1, 1995, the reduction of rental payments due under certain leases of other widebody aircraft. Pending discussions with lessors, Continental has indicated that it will not be making payments to such lessors as required by the terms of its contracts. Continental has approached PCI to request discussions regarding the return of one A-300 aircraft and the renegotiation of certain other leases of widebody aircraft. Continental has indicated that payments under these leases could include debt securities convertible into equity in lieu of full cash payments. PCI has informed Continental that it expects all lease obligations to be satisfied in full. There can be no assurance that PCI will be able to obtain new leases, sell or otherwise dispose of aircraft on satisfactory terms, following scheduled or unscheduled lease terminations. 61 (14) Supplemental Cash Flow Information ---------------------------------- Listed below is supplemental disclosure of cash flow information. - ----------------------------------------------------------------- 1994 1993 1992 - ----------------------------------------------------------------- (Thousands of Dollars) Cash paid for: Interest, net of capitalized interest (including nonutility subsidiary interest of $83,724, $76,556 and $86,917) $203,013 206,955 204,657 Income taxes $ 51,368 67,741 52,764 Nonutility subsidiary noncash transactions: Promissory note received in exchange for equipment $ - - 10,000 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. 62 (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. The Company's equity investment in PCI was reduced from $295 million to $271.1 million at December 31, 1994, by a $23.9 million allowance against retained income to recognize year-end unrealized depreciation of marketable securities on an after-tax basis. Subsidiary equity at December 31, 1993 was $290.9 million. Dividends to the parent company were $15 million in 1994 and $14 million in 1993. - ----------------------------------------------------------------- For the year ended December 31, 1994 1993 1992 - ----------------------------------------------------------------- (Thousands of Dollars) Income Leasing activities $111,262 $114,226 $122,087 Marketable securities 35,148 38,417 37,062 Other 596 (13,302) 2,005 -------- -------- -------- 147,006 139,341 161,154 -------- -------- -------- Expenses Interest 84,783 77,861 86,156 Administrative and general 10,259 14,640 9,762 Depreciation and operating 55,571 66,817 34,559 Income tax (credit) expense (22,695) (45,078) 2,516 -------- -------- -------- 127,918 114,240 132,993 -------- -------- -------- Net earnings from nonutility subsidiary $ 19,088 $ 25,101 $ 28,161 ======== ======== ======== 63 Marketable Securities - --------------------- In January 1994, PCI adopted SFAS No. 115 entitled "Accounting for Certain Investments in Debt and Equity Securities." At December 31, 1994, PCI's marketable securities, all of which are classified as available-for-sale as defined by SFAS No. 115, consist primarily of investment grade preferred stocks with mandatory redemption features. Pursuant to SFAS No. 115, net unrealized gains and losses on such securities are reflected, net of tax, in stockholder's equity. At December 31, 1993, preferred stock with mandatory redemption features and corporate debt securities were generally carried at cost and amortized cost, respectively. Certain of these securities which the Company believed had been permanently impaired were carried at estimated net realizable value. Equity securities at December 31, 1993 were carried at the lower of cost or market and any unrealized losses thereon were recognized, net of tax, in stockholder's equity. 64
- ----------------------------------------------------------------------------------------- December 31, 1994 1993 --------------------------------------------------------------- Gross Market Unrealized Carrying Market Cost Value Losses Value Value - ----------------------------------------------------------------------------------------- (Thousands of Dollars) Mandatory redeemable preferred stock $ 511,791 $ 473,608 $ (38,183) $ 465,034 $ 472,633 Debt securities - - - 1,116 518 Equity securities 3 - (3) 3 - ---------- ---------- ---------- ---------- ---------- Total $ 511,794 $ 473,608 $ (38,186) $ 466,153 $ 473,151 ========== ========== ========== ========== ========== - ----------------------------------------------------------------------------------------- 65
Net recognized gains from marketable securities amounted to $7 million and $7.5 million in 1993 and 1992, respectively. At December 31, 1994, the contractual maturities (in thousands of dollars) for mandatory redeemable preferred stock are shown below. Within one year $ 13,192 One to five years 50,247 Five to ten years 189,797 Over ten years 258,555 -------- Less gross unrealized 511,791 losses (38,183) -------- $473,608 ======== In determining gross realized gains and losses on sales or maturities of securities, specific identification is used. For the Year Ended December 31, 1994 ------------------ (Thousands of Dollars) Gross realized gains $ 2,889 Gross realized losses (2,139) ------- Net gain $ 750 ======= 66 Leasing Activities - ------------------ PCI's net investment in finance leases consists primarily of direct finance leases and are summarized below. - ----------------------------------------------------------------- December 31, 1994 1993 - ----------------------------------------------------------------- (Thousands of Dollars) Rents receivable $517,052 $419,284 Estimated residual values 153,814 155,187 Less: Unearned and deferred income (260,539) (215,947) -------- -------- Investment in finance leases 410,327 358,524 Less: Deferred taxes arising from finance leases (134,925) (130,833) -------- -------- Net investment in finance leases $275,402 $227,691 ======== ======== - ----------------------------------------------------------------- Minimum lease payments receivable from finance leases, primarily aircraft, for each of the years 1995 through 1999 are $43.5 million, $32.3 million, $27.1 million, $31.2 million and $30 million, respectively. Net income from leveraged leases was $5.6 million in 1994, $1.1 million in 1993 and $7.1 million in 1992. Rent payments receivable from aircraft equipment operating leases for each of the years 1995 through 1999 are $49.1 million in 1995, $44.8 million in 1996, $42.5 million in 1997, $33.8 million in 1998 and $29.1 million in 1999. During 1994, PCI purchased and leased back to a Dutch electric generating company a one-third undivided interest in a recently-constructed 650 megawatt (gross) baseload, coal and gas fired power plant located in the Netherlands. PCI's equity investment totaled $60 million and is accounted for as a leveraged lease. In September 1992, PCI entered into an operating lease, as lessee of two aircraft with monthly rental payments of approximately $850,000. The lease is scheduled to terminate in September 1997. 67 (16) Quarterly Financial Summary (Unaudited)
- --------------------------------------------------------------------------------------------------------------------- 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter Total - --------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars except Per Share Data) 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 0.02 1.95 Dividends Per Share $ .41 .41 .41 .41 1.64 1992 Operating Revenue $ 321,119 381,294 544,753 315,001 1,562,167 Total Revenue $ 325,946 390,536 553,631 331,445 1,601,558 Operating Expenses $ 296,616 320,874 405,903 298,712 1,322,105 Operating Income $ 29,330 69,662 147,728 32,733 279,453 Income Before Cumulative Effect of Accounting Change $ 8,049 49,159 122,804 20,748 200,760 Cumulative Effect of Accounting Change, Net of Income Taxes $ 16,022 - - - 16,022 Net Income $ 24,071 49,159 122,804 20,748 216,782 Earnings for Common Stock $ 20,667 45,839 119,243 16,641 202,390 Earnings Per Common Share Before Cumulative Effect of Accounting Change $ .04 .41 1.06 .15 1.66 Cumulative Effect of Accounting Change $ .14 - - - .14 Total $ .18 .41 1.06 .15 1.80 Dividends Per Share $ .40 .40 .40 .40 1.60 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. 68
Stock Market Information
- ----------------------------------------------------------------------------------------------------------------------------- 1994 High Low 1993 High Low - ----------------------------------------------------------------------------------------------------------------------------- 1st Quarter $26-5/8 $21-3/4 1st Quarter $26-1/2 $23-7/8 2nd Quarter $23-1/2 $18-1/2 2nd Quarter $27-3/8 $25-5/8 3rd Quarter $21-1/2 $18-3/8 3rd Quarter $28-7/8 $27-1/8 4th Quarter $19-3/4 $18-1/4 4th Quarter $28-3/4 $24-5/8 (Close $18-3/8) (Close $26-3/4) Shareholders at December 31, 1994: 96,638 - -----------------------------------------------------------------------------------------------------------------------------
Selected Consolidated Financial Data
- ----------------------------------------------------------------------------------------------------------------------------- 1994 1993 1992 1991 1990 1989 1984 - ----------------------------------------------------------------------------------------------------------------------------- (Thousands except Per Share Data) Operating Revenue $1,790,600 1,702,442 1,562,167 1,552,066 1,411,713 1,394,909 1,197,534 Total Revenue $1,823,074 1,725,205 1,601,558 1,619,315 1,501,728 1,531,024 1,363,998 Operating Expenses $1,498,581 1,400,543 1,322,105 1,329,084 1,245,579 1,256,553 1,129,148 Net Earnings from Nonutility Subsidiary $ 19,088 25,101 28,161 23,351 5,035 31,100 6,618 Income Before Cumulative Effect of Accounting Change $ 227,162 241,579 200,760 210,164 170,234 214,587 168,184 Cumulative Effect of Accounting Change, Net of Income Taxes $ - - 16,022 - - - - Net Income $ 227,162 241,579 216,782 210,164 170,234 214,587 168,184 Earnings for Common Stock $ 210,725 225,324 202,390 197,866 159,636 205,352 152,331 Average Common Shares Outstanding 118,006 115,640 112,390 105,911 98,621 95,203 94,340 Earnings Per Common Share Utility Operations $ 1.63 1.73 1.55 1.65 1.57 1.83 1.54 Nonutility Subsidiary $ .16 .22 .25 .22 .05 .33 .07 Consolidated $ 1.79 1.95 1.80 1.87 1.62 2.16 1.61 Cash Dividends Per Common Share $ 1.66 1.64 1.60 1.56 1.52 1.46 0.97 Investment in Property and Plant $5,938,031 5,665,141 5,367,624 5,048,121 4,659,280 4,270,718 3,201,287 Net Investment in Property and Plant $4,298,260 4,131,142 3,931,257 3,706,866 3,397,992 3,097,532 2,374,217 Utility Assets $5,291,467 5,000,328 4,478,762 4,174,713 3,852,415 3,528,883 2,801,091 Nonutility Subsidiary Assets $1,674,289 1,665,132 1,663,508 1,679,079 1,387,247 1,113,827 264,366 Total Assets $6,965,756 6,665,460 6,142,270 5,853,792 5,239,662 4,642,710 3,065,457 Long-Term Utility Obligations (including redeemable preferred and preference stock) $1,866,962 1,736,621 1,727,609 1,662,157 1,516,073 1,286,429 1,096,272 - ----------------------------------------------------------------------------------------------------------------------------- The 1992 earnings per share amount from utility operations includes $.14 as the cumulative effect of an accounting change for unbilled revenue. 69
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