ITEM 1. BUSINESS
THE COMPANY Pennsylvania Power & Light Company (Company) is an operating electric utility, incorporated under the laws of the Commonwealth of Pennsylvania in 1920.
The Company's general offices are located at Two North Ninth Street, Allentown, Pennsylvania 18101. The Company's telephone number is (610) 774-5151.
The Company is subject to regulation as a public utility by the Pennsylvania Public Utility Commission (PUC) and is subject in certain of its activities to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under Parts I, II and III of the Federal Power Act. The Company is a holding company under the Public Utility Holding Company Act of 1935 (PUHCA) but has been exempted by the Securities and Exchange Commission from the provisions of that Act applicable to it as a holding company.
The Company is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC) in connection with the operation of the two nuclear-fueled generating units at the Company's Susquehanna station. The Company owns a 90% undivided interest in each of the Susquehanna units and Allegheny Electric Cooperative, Inc. owns a 10% undivided interest in each of those units.
The Company is also subject to the jurisdiction of certain federal, regional, state and local regulatory agencies with respect to air and water quality, land use and other environmental matters. The operations of the Company are subject to the Occupational Safety and Health Act of 1970 and the coal cleaning and loading operations of a Company subsidiary are subject to the Federal Mine Safety and Health Act of 1977.
The Company operates its generation and transmission facilities as part of the Pennsylvania-New Jersey-Maryland Interconnection Association (PJM). The PJM, one of the world's largest power pools, includes 11 companies serving about 21 million people in a 50,000 square mile territory covering all or part of Pennsylvania, New Jersey, Maryland, Delaware, Virginia and Washington, D.C.
The Company serves approximately 1.2 million customers in a 10,000 square mile territory in 29 counties of central eastern Pennsylvania (see Map on page 17), with a population of approximately 2.6 million persons. This service area has 128 communities with populations over 5,000, the largest cities of which are Allentown, Bethlehem, Harrisburg, Hazleton, Lancaster, Scranton, Wilkes-Barre and Williamsport.
During 1994, about 98% of total operating revenue was derived from electric energy sales, with 35% coming from residential customers, 28% from commercial customers, 20% from industrial customers, 11% from contractual sales to other major utilities, 3% from energy sales to members of the PJM and 3% from others. The Company's largest industrial customer provided about 1.4% of revenues from energy sales during 1994. Twenty-six industrial customers, whose billings exceeded $3 million each, provided about 7.1% of such revenues. Industrial customers are broadly distributed among industrial classifications.
Wholly owned subsidiary companies of the Company principally are engaged in oil pipeline operations, unregulated business activities, passive financial investments and holding coal reserves. See "Increasing Competition" on page 42 for information concerning the Company's ongoing effort to create a new corporate structure to pursue new business opportunities.
FINANCIAL CONDITION
Earnings per share of common stock were $1.41 in 1994, $2.07 in 1993 and $2.02 in 1992.
Earnings for 1994 were adversely affected by several one-time charges, including two major charges during the fourth quarter. One charge amounted to $75.9 million, or 28 cents per share of common stock, resulting from costs associated with a voluntary early retirement program; and the other charge amounted to $73.7 million, or 26 cents per share, from a write down in the carrying value of a subsidiary's investment in undeveloped coal reserves. In addition, two nonrecurring charges recorded earlier in the year reflected the disallowance by the PUC of recovery through the Energy Cost Rate (ECR) of replacement power costs incurred during an extended outage at the Susquehanna station, amounting to $15.7 million, or 6 cents per share of common stock; and a decision by the Commonwealth Court of Pennsylvania which reversed a PUC order that permitted deferral of the cost of postretirement benefits other than pensions. The Company charged the deferred postretirement benefit costs applicable to 1993 against income, which amounted to $10.8 million or 4 cents per share.
Although these nonrecurring charges depressed earnings in 1994, underlying sales performance was strong, with a 4.1% increase in sales to ultimate customers due to improving economic conditions and colder-than-normal weather in the winter months. Other positive effects on earnings included the Company's continued efforts to control operating and maintenance costs, and the refinancing of higher cost securities to take advantage of favorable market conditions.
Due to the one-time charges to income in 1994, several financial indicators decreased from 1993. The Company earned an 8.73% return on average common equity during 1994, down from the 13.06% earned in 1993. The ratio of the Company's pre-tax income to interest charges decreased from 3.3 in 1993 to 2.7 in 1994. Excluding these one-time charges, the return on average common equity and the ratio of pre-tax income to interest charges in 1994 would have been 12.53% and 3.1, respectively. See "Earnings" on page 28. The Company increased common stock dividends from an annual per share rate of $1.65 in 1993 to $1.67 in 1994. The book value per share of common stock decreased 1.0% from $15.95 at the end of 1993 to $15.79 at the end of 1994. The ratio of the market price to book value of common stock was 120% at the end of 1994 compared with 169% at the end of 1993.
The allowance for funds used during construction (AFUDC), a non- cash credit to income, accounted for about 6.1% of earnings in 1994. The amount of AFUDC recorded in the future will depend on the timing and level of construction work in progress as well as the rate treatment afforded the capital expenditures required to comply with the clean air legislation. Under current Pennsylvania law, construction work in progress for certain non-revenue producing assets, such as capital expenditures for pollution control equipment, can be claimed in rate base.
The Company's strong generating capacity position has enabled it to enter into a number of capacity-related transactions, as discussed under "Capacity-Related and Transmission Entitlement Transactions" on page 29 and in Note 4 to Financial Statements.
Revenues from the sale of capacity credits, the reservation of output from the generating units and the sale of transmission entitlements, net of foregone PJM interchange savings which are included in the Company's ECR, totaled $28.7 million in 1994, $35.0 million in 1993 and $35.0 million in 1992. The 1994 revenues exclude approximately $8.4 million of receipts from installed capacity credit sales which were credited to customers through the ECR. The Company currently expects about $14.6 million of revenues from these transactions during 1995, exclusive of credits to be applied to the ECR.
The Company is continuing to look for opportunities to derive additional revenues from these transactions due to its strong generating capacity position. However, increased competition in capacity credit transactions has reduced the Company's share of this market and the unit price received for such sales. The amount of revenues from these transactions depends on many factors, and the Company cannot predict the amount of revenues it will ultimately realize from these transactions.
In October 1994, the PUC approved a settlement agreement resolving all complaints against the 1990-91 ECR through 1993-94 ECR, including issues related to capacity-related transactions. The agreement provides, among other things, for crediting the 1994-95 ECR with a portion of the receipts from capacity credit sales. See "Rate Matters" on page 30 for additional information.
Economic activity in the Company's service territory continued to increase in 1994. Energy sales to service area customers, when adjusted for normal weather, increased by 1.1 billion kilowatt-hours (kwh), or 3.5%, over 1993. By comparison, weather-normalized energy sales in 1993 increased by only 2.8% over 1992 levels.
In 1994, residential sales and commercial sales, when adjusted for normal weather, increased by 2.2% and 3.5%, respectively, over 1993. Industrial sales, which are not affected by the weather, were up 4.8%. System sales in 1995 are currently forecasted to be approximately 32.5 billion kwh, an increase of 136 million kwh, or 0.4%, over 1994 actual system sales, and a 419 million kwh, or 1.3%, increase over 1994 weather-normalized sales.
The electric utility industry, including the Company, has experienced and will continue to experience a significant increase in the level of competition in the energy supply market. The Energy Policy Act of 1992 (Energy Act) is having a significant impact on the Company and the electric utility industry, primarily through amendments to the PUHCA that create a new class of independent power producers, and amendments to the Federal Power Act that open access to electric transmission systems for wholesale transactions. In response to this increased competition, the Company has undertaken strategic initiatives to strengthen its position in the market.
In the wholesale supply market, the Company has entered into new five-year supply agreements at reduced prices with its existing wholesale customers. In addition, the Company is actively participating in negotiations and proceedings involving the sale of electricity to wholesale customers currently served by other utilities.
While there is currently no comparable competition in the retail electric market, the Company anticipates similar competitive pressures in that market in the future. Accordingly, the Company has obtained PUC approval to enter into negotiated, competitive rates with certain industrial and commercial customers and to provide real time pricing rates on a three-year experimental basis to certain industrial and commercial customers.
To remain competitive, the Company also has taken steps to increase efficiency and reduce costs. The Company has initiated a program to make its generating stations more efficient and competitive in the power supply market. In addition, the Company has reorganized its operations along functional, instead of geographic, lines to enhance customer service. The Company's ongoing re- engineering efforts also are expected to improve efficiency and reduce costs. As part of its effort to reduce costs, the Company in 1994 offered an early retirement program to 851 employees, which was accepted by 640 employees.
Finally, the Company's strategic initiatives include investment in power-related businesses outside of the Company's service territory, both domestically and in foreign countries. Any expansion by the Company into these areas would be methodical and deliberate. To take advantage of these new business opportunities, the Company will form a holding company structure, subject to the receipt of appropriate regulatory approvals and shareowner approval at the 1995 annual meeting.
In March 1994, the Company incorporated a new subsidiary, Power Markets Development Company (PMD), and made an initial investment of $50 million in this new subsidiary. PMD will help the Company take advantage of new opportunities in the building and operation of power plants in North America and elsewhere. Other subsidiaries will be formed to take advantage of new business opportunities.
In connection with the formation of the holding company structure, the Company filed the requisite applications for approval with the PUC, the FERC, the Securities and Exchange Commission (SEC) and the NRC. The FERC, the NRC and the PUC approvals have been obtained, while the SEC application remains pending. The PUC approval is subject to certain conditions, which are not expected to materially restrict the Company's entry into unregulated business activities.
For a further discussion of these competitive initiatives, see "Increasing Competition" on page 41.
For a discussion of the assessment on the Company pursuant to the Energy Act for the Uranium Enrichment Decontamination and Decommissioning Fund, see the discussion under that caption on page 40.
CAPITAL EXPENDITURE REQUIREMENTS, FINANCING AND RATE MATTERS
See "Capital Expenditure Requirements" on page 34 for information concerning the Company's estimated capital expenditure requirements for the years 1995-1997. See "Clean Air Legislation and Other Environmental Matters" on page 37 and Note 15 to Financial Statements for information concerning the Company's estimate of the cost to comply with the federal clean air legislation enacted in 1990, to address groundwater degradation and waste water control at Company facilities and to comply with solid waste disposal regulations adopted by the Pennsylvania Department of Environmental Resources (DER).
After the payment of dividends, internally generated funds during the years 1995-1997 are currently expected to provide approximately 70-85% of the Company's construction expenditures which are expected to be $1.3 billion. Sales of securities will be undertaken during the 1995-1997 period as needed to meet the Company's capital requirements, to meet a total of $211 million of long-term debt maturities and to provide funds for the early retirement of high cost securities if such retirements are determined to be appropriate in the light of market conditions and other factors. The Company expects to issue $180 million of common stock in 1995 through its Dividend Reinvestment Plan and a public sale of common stock. In addition, the Company expects to arrange for the refinancing of $55 million of higher cost tax-exempt securities issued to provide pollution control and solid waste disposal facilities at the Company's generating stations.
The Company's ability to issue securities during the next three years is not expected to be limited by earnings or other issuance tests.
In December 1994, the Company filed a request with the PUC for a $261 million increase in electric base rates, an 11.7% increase in PUC - jurisdictional rates. The PUC has decided to hold hearings and conduct an investigation of the request. A final rate decision is expected in late September 1995. See Note 3 to Financial Statements for information concerning the base rate case and other rate matters.
POWER SUPPLY
The Company's system capacity (winter rating) at December 31, 1994 was as follows: Net Kilowatt Plant Capacity Nuclear-fueled steam station Susquehanna 1,950,000 (a) Coal-fired steam stations Montour 1,525,000 Brunner Island 1,469,000 Sunbury 389,000 Martins Creek 300,000 Keystone 210,000 (b) Conemaugh 194,000 (c) Holtwood 73,000 Total coal-fired 4,160,000 Oil-fired steam station Martins Creek 1,640,000 Combustion turbines and diesels 508,000 Hydroelectric 146,000 Total generating capacity 8,404,000 Firm purchases Hydroelectric 139,000 (d) Qualifying facilities 504,000 (e) Total firm purchases 643,000 Total system capacity 9,047,000 _____________________________ (a) Company's 90% undivided interest. (b) Company's 12.34% undivided interest. (c) Company's 11.39% undivided interest. (d) From Safe Harbor Water Power Corporation. (e) From non-utility generating companies.
The system capacity shown in the preceding tabulation does not reflect: (i) sales of capacity and energy to Atlantic City Electric Company (Atlantic) through September 2000; (ii) sales of capacity and energy to Baltimore Gas and Electric Company (BG&E) through 2001; (iii) sales of capacity and energy to Jersey Central Power & Light Company (JCP&L) through 1999; or (iv) sales of capacity credits to GPU Service Corporation for PJM installed capacity accounting purposes only, which capacity credit sales aggregated 390,000 kilowatts at December 31, 1994. Giving effect to the sales to Atlantic (125,000 kilowatts), BG&E (129,000 kilowatts) and JCP&L (945,000 kilowatts), the Company's net system capacity at December 31, 1994 was 7,844,000 kilowatts.
The capacity of generating units is based upon a number of factors, including the operating experience and physical condition of the units, and may be revised from time to time to reflect changed circumstances.
During 1994, the Company produced about 37.9 billion kwh in plants owned by it. The Company purchased 5.0 billion kwh under purchase agreements and received 1.0 billion kwh as power pool interchange. During the year, the Company delivered about 3.2 billion kwh as pool interchange and about 0.4 billion kwh under purchase agreements.
During 1994, 56.9% of the energy generated by the Company's plants came from coal-fired stations, 36.4% from nuclear operations at the Susquehanna station, 4.7% from the Martins Creek oil-fired steam station and 2.0% from hydroelectric stations.
The maximum one-hour demand recorded on the Company's system is 6,508,000 kilowatts, which occurred on February 6, 1995. The maximum recorded one-hour summer demand is 5,638,000 kilowatts, which occurred on July 20, 1994. The peak demands do not include energy sold to Atlantic, BG&E or JCP&L.
The Company purchases energy from other utilities when it is economically desirable to do so. The Company occasionally purchases energy from systems located to the west of the Company's service area on a weekly basis at advantageous prices. The amount of energy purchased depends on a number of factors, including cost and the import capability of the transmission network. When it has been economical to do so, the Company has sold portions of its entitlement to use the bulk power transmission system to import energy from utilities outside the PJM, rather than utilize its entitlement for purchases from such western systems.
The Company also has entered into separate agreements with several utilities in New York and New England to provide energy on an as available, as needed basis. Transactions under these agreements are expected to continue to allow the Company to make more efficient use of its generating capacity and provide benefits to customers of both the Company and the purchasing utilities. The Company also has entered into agreements with several utilities both inside and outside the PJM for the reservation of output during certain periods from the Company's Martins Creek units, with the option to purchase energy from those units.
See "Capacity-Related and Transmission Entitlement Transactions" on page 29 and Note 4 to Financial Statements for additional information concerning the sale of capacity and energy to Atlantic, BG&E and JCP&L, the sale of capacity credits (but not energy) to other electric utilities in the PJM and the sale of transmission entitlements and the reservation of output from the Martins Creek units. See "Rate Matters" on page 30 and Note 3 to Financial Statements for information concerning a settlement agreement between the Company and ECR complainants with respect to capacity-related transactions.
In addition to the 504,000 kilowatts of non-utility generation shown in the preceding tabulation, the Company is purchasing about 3,000 kilowatts of output from various other non-utility generating companies. The payments made to non-utility generating companies, all of whose facilities are located in the Company's service area, are recovered from customers through the ECR applicable to PUC- jurisdictional customers and base rate charges applicable to FERC- jurisdictional customers.
The PJM companies had approximately 56 million kilowatts of installed generating capacity at December 31, 1994, and transmission line connections with neighboring power pools have the capability of transferring an additional 4 to 5 million kilowatts between the PJM and neighboring power pools. Through December 31, 1994, the maximum one-hour demand recorded on the PJM was approximately 46.4 million kilowatts, which occurred on July 8, 1993. The Company is also a party to the Mid-Atlantic Area Coordination Agreement, which provides for the coordinated planning of generation and transmission facilities by the companies included in the PJM.
The Company currently plans to convert the two oil-fired generating units at the Martins Creek station to burn both oil and natural gas, subject to appropriate regulatory approvals. A Company subsidiary filed an application with the PUC for authority to also transport natural gas through the pipeline to the existing pipeline customers, which include the Company and another utility. Two parties have protested the subsidiary's application, asserting that they have the sole authority to provide such gas service to the Company and the other utility, respectively. The matter is presently being litigated at the PUC and the Company cannot predict the outcome.
FUEL SUPPLY
Coal
During 1994, the Company's generating stations burned about 7.8 million tons of bituminous coal and about 1.2 million tons of anthracite and petroleum coke.
During 1994, 78% of the coal delivered to the Company's generating stations was purchased under contracts and 22% was obtained through open market purchases.
The amount of bituminous coal carried in inventory at the Company's generating stations varies from time to time depending on market conditions and plant operations. As of December 31, 1994, the Company's bituminous coal supply was sufficient for about 48 days of operations.
Contracts with non-affiliated coal producers provided the Company with about 5.4 million tons of bituminous coal in 1994 and are expected to provide the Company with about 5.4 million tons in both 1995 and 1996.
A wholly owned subsidiary of the Company also holds certain undeveloped coal reserves which the Company does not plan to develop. At December 31, 1994, the investment by the subsidiary in those coal reserves was about $10 million. See "Write Down of Coal Reserves" on page 41 and Note 14 to Financial Statements for information concerning the impairment of the subsidiary's investment in these coal reserves.
The coal burned in the Company's generating stations contains both organic and pyritic sulfur. Mechanical cleaning processes are utilized to reduce the pyritic sulfur content of the coal. The reduction of the pyritic sulfur content by either mechanical cleaning or blending has lowered the total sulfur content of the coal burned to levels which permit compliance with current sulfur dioxide emission regulations established by the DER. For information concerning the Company's plans to achieve compliance with the federal clean air legislation enacted in 1990, see "Clean Air Legislation and Other Environmental Matters" on page 37 and Note 15 to Financial Statements.
The Company owns a 12.34% undivided interest in the Keystone station and an 11.39% undivided interest in the Conemaugh station, both of which are generating stations located in western Pennsylvania. The owners of the Keystone station have a long-term contract with a coal supplier to provide at least two-thirds of that station's requirements through 1999 and declining amounts thereafter until the contract expires at the end of 2004. The balance of the Keystone station requirements are purchased in the open market. The coal supply requirements for the Conemaugh station are being met from several sources through a blend of long-term and short-term contracts and spot market purchases.
At December 31, 1994, the Company's inventory of anthracite was about 4.9 million tons. The Company's requirements for petroleum coke and any additional anthracite that may be required over the remainder of the expected useful lives of the Company's anthracite- fired generating stations are expected to be obtained by contract and market purchases.
Nuclear
The nuclear fuel cycle consists of the mining of uranium ore and its milling to produce uranium concentrates; the conversion of uranium concentrates to uranium hexafluoride; the enrichment of uranium hexafluoride; the fabrication of fuel assemblies; the utilization of the fuel assemblies in the reactor; the temporary storage of spent fuel; and the permanent disposal of spent fuel.
The Company has entered into uranium supply agreements that, together with options to extend, satisfy 100% of the uranium concentrate requirements for the Susquehanna units through 1997, approximately 70% of the requirements for the period 1998-1999, and approximately 35% of the requirements for the period 2000-2001. Deliveries under these agreements are expected to provide sufficient quantities of uranium concentrates to permit Unit 1 to operate into the third quarter of 1999 and Unit 2 to operate into the third quarter of 1998.
The Company has entered into agreements that satisfy 100% of its conversion requirements through 1997 and approximately 25% of the conversion requirements for the period 1998-1999.
The Company also has entered into agreements for other segments of the nuclear fuel cycle. Based upon the current operating plans for each of the Susquehanna units, the following tabulation shows the years through which contracts, including options to extend, could provide the indicated segments of the nuclear fuel cycle:
Enrichment 2014 Fabrication 2004
The Company has elected to cancel all or a portion of deliveries under its existing enrichment contract during the period 1999 through 2002, and plans to competitively bid those requirements on the open market. Additional arrangements will be necessary to satisfy the remaining fuel requirements of the Susquehanna units over their anticipated useful lives.
The Company estimates that there is sufficient storage capability in the spent fuel pools at Susquehanna to accommodate the fuel that is expected to be discharged through the year 1997. Federal law requires the federal government to provide for the permanent disposal of commercial spent nuclear fuel. Pursuant to the requirements of that law, the United States Department of Energy (DOE) has initiated an analysis of a site in Nevada for a permanent nuclear waste repository. The most recent estimated in-service date for the repository is beyond 2010. However, the location of the site for the repository in Nevada has been opposed by the state of Nevada. The DOE is also pursuing implementation of a Monitored Retrievable Storage (MRS) facility which is intended to permit the receipt of spent nuclear fuel for interim storage by the year 1998, or shortly thereafter. Even if the DOE is successful in implementing its plans for the MRS, it is unlikely that any spent fuel will be shipped from Susquehanna until well after the year 2000 because of the limited capacity of the MRS and the large volume of other utilities' spent fuel that is scheduled to be shipped before the Company's spent fuel. Therefore, expansion of Susquehanna's spent fuel storage capability will be necessary. To support this expansion, a contract was recently signed providing for the design and construction of a new spent fuel storage facility at the Susquehanna plant. The facility will be modular so that additional storage capacity can be added as needed. The Company currently estimates that the initial construction will be completed in the spring of 1997.
Federal law also provides that the costs of spent nuclear fuel disposal will be the responsibility of the generators of such wastes. The Company includes in customer rates the fees charged by the DOE to fund the permanent disposal of spent nuclear fuel.
For a discussion of the assessment on the Company pursuant to the Energy Act for the Uranium Enrichment Decontamination and Decommissioning Fund, see the discussion under that caption on page 40.
Oil
The Company has agreements with two suppliers under which it can purchase its expected oil requirements for the Martins Creek units. However, if there are price advantages to be realized from purchasing oil in the spot market, these contracts permit the Company to acquire up to one-half of its expected oil requirements for the Martins Creek units in that manner. One oil purchase agreement expired in mid-1994 and was replaced with a similar two-year agreement which will expire in mid-1996. The other agreement expires in mid-1995.
During 1994, approximately 80% of the oil requirements for the Martins Creek units was purchased under the Company's oil contracts and the balance was purchased on the spot market.
See "POWER SUPPLY" on page 6 for information concerning the planned conversion of the two oil-fired generating units at the Martins Creek station to burn both oil and natural gas.
ENVIRONMENTAL MATTERS
The Company is subject to certain present and developing federal, regional, state and local laws and regulations with respect to air and water quality, land use and other environmental matters. See "Capital Expenditure Requirements" on page 34 for information concerning environmental expenditures during the years 1992-1994 and the Company's estimate of those expenditures during the years 1995- 1997. The Company believes that it is presently in substantial compliance with applicable environmental laws and regulations.
See "Clean Air Legislation and Other Environmental Matters" on page 37 and Note 15 to Financial Statements for information concerning federal clean air legislation enacted in 1990, groundwater degradation and waste water control at Company facilities, DER's solid waste disposal regulations, the Company's negotiations with the DER concerning remediation at certain sites of past operations, and the issue of electric and magnetic fields. Other environmental laws, regulations and developments that may have a substantial impact on the Company are discussed below.
Air
The Federal Clean Air Act includes, among other things, provisions that: (a) require the prevention of significant deterioration of existing air quality in regions where air quality is better than applicable ambient standards; (b) restrict the construction of and revise the performance standards for new coal- fired and oil-fired generating stations; and (c) authorize the United States Environmental Protection Agency (EPA) to impose substantial noncompliance penalties of up to $25,000 per day of violation for each facility found to be in violation of the requirements of an applicable state implementation plan. The DER administers the EPA's air quality regulations through the Pennsylvania State Implementation Plan and has concurrent authority to impose penalties for noncompliance.
As a result of computer dispersion modeling of the effects of the Company's Martins Creek station (located in Pennsylvania) on ambient air quality in New Jersey, the EPA redesignated Warren County, New Jersey to non-attainment status for sulfur dioxide, effective February 1, 1988. However, the EPA withheld further regulatory action until the Company, the EPA, the DER and the New Jersey Department of Environmental Protection (NJDEP) could agree upon and apply a computer model that will more accurately predict the actual ambient air quality of the area. The Company negotiated with the EPA, the DER and the NJDEP on a study to allow the use of a more accurate model. This study began in May 1992 and is expected to be concluded in 1996. In addition, the regulatory agencies have required the Company to expand the study area beyond the designated sulfur dioxide non-attainment area to include any predicted "areas of concern" in the vicinity of the plant. The Company is developing a study to address this expanded area. If it is determined that the Martins Creek operations are causing ambient air violations, the Company may be required to make changes to reduce sulfur dioxide emissions. However, it is currently expected that the reductions planned to meet the requirements of the Clean Air Act acid rain provisions should be adequate to meet any reduction that may be required as a result of these studies. See "Clean Air Legislation and Other Environmental Matters" on page 37 and Note 15 to Financial Statements.
Water
To implement the requirements established by the Federal Water Pollution Control Act of 1972, as amended by the Clean Water Act of 1977 and the Water Quality Act of 1987, the EPA has adopted regulations including effluent standards for steam electric stations. The DER administers the EPA's effluent standards through state laws and regulations relating, among other things, to effluent discharges and water quality. The standards adopted by the EPA pursuant to the Clean Water Act may have a significant impact on the Company's existing facilities depending on the DER's interpretation and future amendments to its regulations.
The EPA and DER limitations, standards and guidelines for the discharge of pollutants from point sources into surface waters are enforced through the issuance of National Pollutant Discharge Elimination System (NPDES) permits. The Company has NPDES permits necessary for the operation of its facilities.
Pursuant to the Surface Mining and Reclamation Act of 1977 (Reclamation Act), the United States Office of Surface Mining (OSM) has adopted effluent guidelines which are applicable to Company subsidiaries as a result of their past coal mining and continued coal processing activities. The EPA and the OSM limitations, guidelines and standards also are enforced through the issuance of NPDES permits. In accordance with the provisions of the Clean Water Act and the Reclamation Act, the EPA and the OSM have authorized the DER to implement the NPDES program for Pennsylvania sources. Compliance with applicable water quality standards is assured by DER review of NPDES permit conditions. The Company's subsidiaries have received NPDES permits for their mines and related facilities.
Solid and Hazardous Waste
The 1976 Resource Conservation and Recovery Act (RCRA) regulates the generation, transportation, treatment, storage and disposal of hazardous wastes. RCRA also imposes joint and several liability on generators of solid or hazardous waste for clean-up costs. A revision of RCRA in late 1984 lowered the threshold for the amount of on-site hazardous waste generation requiring regulation and incorporated underground tanks used for the storage of petroleum and petroleum products as regulated units. Based upon the results of a survey of its solid waste practices, the Company in the past has filed notices with the EPA indicating that hazardous waste is occasionally generated at all of its steam electric generating stations and service centers. The Company has established routine operating procedures for handling this hazardous waste. Therefore, at this time RCRA and related DER regulations are not expected to have a significant additional impact on the Company.
The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (Superfund), authorize the EPA to require past and present owners of contaminated sites and generators of any hazardous substance found at a site to clean up the site or pay the EPA or the state for the costs of clean- up. The generators and past owners can be liable even if the generator contributed only a minute portion of the hazardous substances at the site. Present owners can be liable even if they contributed no hazardous substances to the site.
In 1981 the Company was notified by the EPA that the Company could be liable for the cost of removing coal tar deposits discovered at a former gas plant site owned by the Company along Brodhead Creek in Monroe County, Pennsylvania, and on adjacent property owned by a company unrelated to the Company. The EPA used Superfund monies to construct a slurry wall which was paid for by the adjacent property owner. The Company removed approximately 8,000 gallons of coal tar from its property. To determine whether additional work needed to be done, a Remedial Investigation and a Risk Assessment were conducted by the Company and the adjacent property owner and submitted to the EPA and the DER. Although the Risk Assessment showed acceptable risk levels, the EPA and the DER required a Feasibility Study to identify whether additional remedial action was required.
Based on the results of that Feasibility Study and other investigations, the Company and the adjacent property owner signed a consent decree with the EPA in November 1991. Under the terms of that consent decree, the Company and the adjacent property owner will remove two subsurface coal tar accumulations, monitor the site for up to 30 years and pay all past unreimbursed and all future EPA oversight costs. The Company's share of the costs associated with the consent decree is estimated to be about $2 million.
In May 1992, the Company and the adjacent property owner signed a consent order from the EPA directing that an additional Remedial Investigation and Feasibility Study be performed to address groundwater contamination at the site. This investigation is now underway and could result in the EPA requiring additional site remediation, the cost of which cannot now be determined but could be material.
The EPA has placed the site of a former Company gas plant in Columbia, Pennsylvania on the national Superfund list. The Company and another potentially responsible party (PRP) had previously conducted a detailed investigation of the site, and the Company removed a substantial amount of coal tar from a pedestrian tunnel at the rear of the property. However, coal tar remains in two brick pits on the site. There also is coal tar contamination of the soil and groundwater at the site and of river sediment adjacent to the site. The Company is negotiating with EPA and DER on additional investigation and remediation required at the site. The costs of investigation and remediation of the areas of the site where the agencies have required action are estimated at $1.2 million, all of which has been spent or is budgeted. Further remediation of other areas of the site may be required, the costs of which are not now determinable but could be material.
The Company at one time also owned and operated several other gas plants in its service area. None of these sites is presently on the Superfund list. However, a few of them may be possible candidates for listing at a future date. The Company expects to continue to investigate and, if necessary, remediate these sites. The cost of this work is not now determinable but could be material.
See "LEGAL PROCEEDINGS" on page 18 for information concerning an EPA order and a complaint filed by the EPA in federal district court against the Company and 35 unrelated parties for remediation of a Superfund site in Berks County, Pennsylvania; a complaint filed by the Company and 16 unrelated parties in federal district court against other parties for contribution under Superfund relating to the Novak landfill site in Lehigh County, Pennsylvania; an EPA complaint in federal district court against the Company and 10 unrelated parties to recover all past and future EPA costs of investigating and remediating the Heleva landfill site in Lehigh County, Pennsylvania; and action by the EPA for reimbursement of the EPA's past response costs and remediation at the site of a former metal salvaging operation in Montour County, Pennsylvania.
The Company is involved in several other sites where it may be required, along with other parties, to contribute to investigation and remediation. Some of these sites have been listed by the EPA under Superfund, and others may be candidates for listing at a future date. Future investigation or remediation work at sites currently under review, or at sites currently unknown, may result in material additional operating costs which the Company cannot estimate at this time. In addition, certain federal and state statutes, including Superfund and the Pennsylvania Hazardous Sites Cleanup Act, empower certain governmental agencies, such as the EPA and the DER, to seek compensation from the responsible parties for the lost value of damaged natural resources. The EPA and the DER may file such compensation claims against the parties, including the Company, held responsible for cleanup of such sites. Such natural resource damage claims against the Company could result in material additional liabilities.
The Pennsylvania Superfund law gives the DER broad authority to identify hazardous or contaminated sites in Pennsylvania and to order owners or responsible parties to clean up the sites. If responsible parties cannot or will not perform the clean-up, the DER can hire contractors to clean up the sites and then require reimbursement from the responsible parties after the clean-up is completed. To date, the Company's involvement in such state sites has been minimal.
Low-Level Radioactive Waste
Under federal law, each state is responsible for the disposal of low-level radioactive waste generated in that state. States may join in regional compacts to jointly fulfill their responsibilities. The states of Pennsylvania, Maryland, Delaware and West Virginia are members of the Appalachian States Low-Level Radioactive Waste Compact. Efforts to develop a regional disposal facility in Pennsylvania are currently underway. Low-level radioactive wastes resulting from the operation of Susquehanna are currently stored onsite. Any additional required storage capacity will have to be provided by the Company. The Company cannot predict the future availability of low-level waste disposal facilities or the cost of such disposal.
General
In addition to the matters described above, the Company and its subsidiaries have been cited from time to time for temporary violations of the DER and EPA regulations with respect to air and water quality and solid waste disposal in connection with the operation of their facilities and may be cited for such violations in the future. As a result, the Company and its subsidiaries may be subject to certain penalties which are not expected to be material in amount.
The Company is unable to predict the ultimate effect of evolving environmental laws and regulations upon its existing and proposed facilities and operations. In complying with statutes, regulations and actions by regulatory bodies involving environmental matters, including the areas of water and air quality, hazardous and solid waste handling and disposal and toxic substances, the Company may be required to modify, replace or cease operating certain of its facilities. The Company may also incur material capital expenditures and operating expenses in amounts which are not now determinable.
FRANCHISES AND LICENSES
The Company has authority to provide electric public utility service throughout its entire service area as a result of grants by the Commonwealth of Pennsylvania in corporate charters to the Company and companies to which it has succeeded and as a result of certification thereof by the PUC. The Company has been granted the right to enter the streets and highways by the Commonwealth subject to certain conditions. In general, such conditions have been met by ordinance, resolution, permit, acquiescence or other action by an appropriate local political subdivision or agency of the Commonwealth.
The Company operates Susquehanna Unit 1 and Unit 2 pursuant to NRC operating licenses which expire in 2022 and 2024, respectively. The Company operates two hydroelectric projects pursuant to licenses which were renewed by the FERC in 1980: Wallenpaupack (44,000 kilowatts capacity) and Holtwood (102,000 kilowatts capacity). The Wallenpaupack license expires in 2004 and the Holtwood license expires in 2014.
The Company also owns one-third of the capital stock of Safe Harbor Water Power Corporation, which holds a project license which extends until 2030 for the operation of its hydroelectric plant. The total capability of the Safe Harbor plant is 417,500 kilowatts, and the Company is entitled by contract to one-third of the total capacity (139,000 kilowatts).
EMPLOYEE RELATIONS
As of December 31, 1994, approximately 4,428 of the Company's 6,934 full-time employees were represented by the International Brotherhood of Electrical Workers under a three-year agreement which expires in May 1997.
Page 17 contains a map of the Company's service territory which shows its location, the location of each of the Company's coal-fired, oil-fired, hydro and nuclear-fueled generating stations and the location of major population centers.
ITEM 2.
ITEM 2. PROPERTIES
The Map on page 17 shows the location of the Company's service area and generating stations.
Reference is made to Exhibit 99 - Schedule of Property, Plant and Equipment for information concerning the Company's investment in property, plant and equipment. Substantially all electric utility plant is subject to the lien of the Company's first mortgage. Additional information concerning capital leases is set forth in Note 8 to Financial Statements.
For additional information concerning the properties of the Company see Item 1, "BUSINESS - Power Supply" and "BUSINESS - Fuel Supply".
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 3 to Financial Statements for information concerning rate matters.
Reference is made to Note 15 to Financial Statements for information concerning two complaints filed against the Company by fuel oil dealers alleging that the Company's promotion of electric heat pumps and off-peak storage systems had violated and continues to violate the federal antitrust laws.
In April 1991, the U.S. Department of Labor through its Mine Safety and Health Administration (MSHA) issued citations to one of the Company's coal-mining subsidiaries for alleged coal-dust sample tampering at one of the subsidiary's mines. The MSHA at the same time issued similar citations to more than 500 other coal-mine operators. Based on a review of its dust sampling procedures, the subsidiary is contesting all of the citations. It is believed at this time, based on the information available, that the MSHA allegations are without merit. Citations were also issued against the independent operator of another subsidiary mine, who is also contesting the citations issued with respect to that mine. The Administrative Law Judge (Judge) assigned to the proceedings ordered that one case be tried against a single mine operator unrelated to the Company to determine whether the MSHA could prove its general allegations regarding sample tampering. In April 1994, the Judge ruled in favor of the mine operator and vacated the 75 citations against it. The MSHA is appealing the Judge's decision to the Mine Safety & Health Review Commission. The other cases, including those involving the Company's subsidiaries, have been stayed pending the outcome of the appeal.
The Company cannot predict the eventual outcome of this matter. If violations are found, it is currently estimated that potential administrative penalties could range from approximately $90,000 to approximately $4.6 million.
On July 25, 1994, Mon Valley Steel Company, Inc. (Mon Valley) filed suit in the Court of Common Pleas of Fayette County, Pennsylvania, against the Company and two of its subsidiaries, claiming that the Company and those subsidiaries made fraudulent misrepresentations during negotiations for the 1992 sale to Mon Valley of Tunnelton Mining Company (Tunnelton). Tunnelton was a coal-mining operation formerly owned by the Company's subsidiary, Pennsylvania Mines Corporation. Specifically, Mon Valley alleges that the Company and those subsidiaries misrepresented Tunnelton's capability to produce coal, as well as the amount of funding Tunnelton would receive for mine closing costs. Mon Valley is claiming about $6 million to cover mine closing costs, as well as punitive damages in an unspecified amount. In July 1994, the Company and those subsidiaries filed a legal action in the Court of Common Pleas of Allegheny County, Pennsylvania, requesting a judicial determination that they had not breached any of their contractual obligations to Mon Valley. The Company cannot predict the outcome of these proceedings.
In August 1991, the Company and 35 other unrelated parties received an Environmental Protection Agency (EPA) order under Section 106 of the federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended (Superfund), requiring that certain remedial actions be taken at a former oil recovery site in Berks County, Pennsylvania, which has been included on the federal Superfund list. The Company had been identified by the EPA as a potentially responsible party, along with over 100 other parties. The EPA order required remediation by the 36 named parties of four specific areas of the site. Remedial action under this order has essentially been completed at a cost of approximately $2 million, of which the Company's share was approximately $50,000.
The EPA at the same time filed a complaint under Section 107 of Superfund in the United States District Court for the Eastern District of Pennsylvania (District Court) against the Company and the same 35 unrelated parties. The complaint asks the District Court to hold the parties jointly and severally liable for all past and future EPA costs of remediating some of the remaining areas of the site. The EPA claims it has spent approximately $21 million to date. The Company and a group of the other named parties have sued in District Court approximately 460 other parties that have contributed waste to the site, demanding that these companies contribute to the clean-up costs.
In July 1993, the Company and 33 of the 35 unrelated parties received an EPA order under Section 106 of Superfund requiring remediation of the remaining areas of the site identified by EPA. Current estimates of remediating the remainder of the site range from $50 million to $200 million. These costs would be shared among the responsible parties. The Company is negotiating with the federal government to settle both the Section 107 and Section 106 actions, for an amount which currently is not expected to be material.
In October 1993, the Pennsylvania Department of Environmental Resources (DER) moved to intervene in the EPA suit, seeking to hold 16 of the originally named parties, including the Company, liable for all past and future DER costs of remediating the site and for any natural resource damages at the site. According to the complaint, the DER has spent at least $800,000 to date. The Company may incur material costs for this DER action in amounts which are not now determinable.
In December 1991, the Company and 16 unrelated parties filed complaints against 64 other parties in District Court seeking reimbursement under Superfund for costs the plaintiffs have incurred and will incur to investigate and remediate the Novak landfill site in Lehigh County, Pennsylvania. The complaints allege that the 64 defendants generated or transported substances disposed of at the Superfund site. A Remedial Investigation and Feasibility Study for the site has been completed at a cost of approximately $3 million, of which the Company's share was approximately $300,000. EPA's selected remedy is currently estimated to cost approximately $20 million. EPA has issued a proposed Consent Decree to the Company and several other parties to implement the remedy. The Company may incur material costs for this matter in amounts which are not now determinable.
In March 1993, the EPA filed a complaint under Section 107 of Superfund in District Court against the Company and 10 unrelated parties to recover all past and future EPA costs of investigating and remediating the Heleva landfill site in Lehigh County, Pennsylvania. The EPA alleges it has spent approximately $10 million to date at this site. The Company has filed an answer to the complaint denying liability based on the absence of evidence that the Company sent any hazardous substances to the site. The Company expects to settle this matter for a sum which currently is not expected to be material.
In April 1993, the Company received an order under Section 106 of Superfund requiring that actions be taken at the site of a former metal salvaging operation in Montour County, Pennsylvania. The EPA has taken similar action with two other potentially responsible parties at the site. The cost of compliance with the order is currently estimated to be approximately $37 million. The EPA currently estimates that additional remediation work not covered by the order will cost an additional $36 million. In addition, the EPA has already incurred clean-up costs of approximately $5 million to date. The EPA had indicated that it will seek to recover these additional costs at a later date. The Company's records indicate that scrap metal, wire and transformers were sold to the salvage operator between 1969 and 1971. Current information indicates that the Company's contribution to the site, if any, is de minimis.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders, through the solicitation of proxies or otherwise, during the fourth quarter of 1994.
EXECUTIVE OFFICERS OF THE REGISTRANT
Officers are elected annually by the Board of Directors to serve at the pleasure of the Board. There are no family relationships among any of the executive officers, or any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.
There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any executive officer during the past five years.
Listed below are the executive officers of the Company:
Effective Date of Election to Name Age Position Present Position
William F. Hecht 51 Chairman, President and Chief Executive Officer January 1, 1993
Francis A. Long 54 Executive Vice President and Chief Operating Officer January 1, 1993
Robert G. Byram 49 Senior Vice President- Nuclear March 26, 1993
Ronald E. Hill 52 Senior Vice President- Financial January 1, 1994
Linda Curry 46 Vice President - Bartholomew Public Affairs June 1, 1989
John R. Biggar 50 Vice President- Finance March 1, 1984
John M. Chappelear 56 Vice President- Investments and Pensions June 1, 1986
Robert M. Geneczko 42 Vice President- Electrical Systems November 1, 1994
Effective Date of Election to Name Age Position Present Position
Robert S. Gombos 51 Vice President- Mobile Work Force November 1, 1994
Robert J. Grey 44 Vice President, General Counsel and Secretary March 6, 1995
Michael D. Hill 52 Vice President-Infor- mation Services August 1, 1993
George T. Jones 47 Vice President-Nuclear Engineering June 1, 1993
John P. Kierzkowski 55 Vice President and Treasurer March 1, 1984
Joseph J. McCabe 44 Controller May 1, 1994
John R. Menichini 47 Vice President- Customer Service November 1, 1994
Robert J. Shovlin 54 Vice President-Power Production and Engineering January 1, 1992
Harold G. Stanley 54 Vice President-Nuclear Operations June 1, 1993
Raymond F. Suhocki 49 Vice President-Marketing and Economic Develop- ment November 1, 1994
Each of the above officers, with the exception of Mr. Grey, Mr. Jones and Mr. McCabe, has been employed by the Company for more than five years as of December 31, 1994. Mr. Jones joined the Company in September 1991 and was previously employed by Entergy Operations, Inc. The positions he held at Entergy Operations, Inc. between January 1990 and September 1991 were General Manager-Engineering and Director of Engineering-Arkansas Nuclear One. Mr. McCabe joined the Company in May 1994 and was previously employed by Deloitte & Touche LLP (Deloitte). He held the position of partner at Deloitte between Janaury 1990 and May 1994. Mr. Grey will join the Company on March 6, 1995. Mr. Grey has been General Counsel of Long Island Lighting Company since 1992. Prior to that time, he held the position of partner at the law firm of Preston, Thorgrimson Shidler Gates & Ellis between 1982 and 1992.
Prior to election to the positions shown above, the following executive officers held other positions with the Company since January 1, 1990: Mr. Hecht was Senior Vice President-System Power and Engineering, Executive Vice President- Operations and President and Chief Operating Officer; Mr. Long was Vice President-Power Supply and Senior Vice President - System Power & Engineering; Mr. Byram was Vice President-Nuclear Operations and Senior Vice President - System Power & Engineering; Mr. R. E. Hill was Vice President and Comptroller; Ms. Bartholomew was Senior Director and Economist-Public Affairs; Mr. Geneczko was Manager-System Planning and Vice President- Division; Mr. Gombos was Vice President-Human Resource and Development; Mr. M. D. Hill was Manager-Bulk Power Engineering and Manager-System Operating; Mr. Jones was Manager-Nuclear Plant Engineering and Manager-Nuclear Engineering; Mr. Menichini was Vice President-Division; Mr. Shovlin was Director-Power Production and Engineering; Mr. Stanley was Superintendent of Plant-Susquehanna Steam Electric Station and Mr. Suhocki was Manager-Marketing & Economic Development, Vice President-Division and Vice President-System Power.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Additional information for this item is set forth in the section entitled "Shareowner and Investor Information" on pages 87 through 89 of this report, and the number of common shareowners is set forth in the section entitled "Selected Financial and Operating Data" on page 85.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Information for this item is set forth in the section entitled "Selected Financial and Operating Data" on pages 85 and 86 of this report.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Information for this item is set forth in the section entitled "Review of the Company's Financial Condition and Results of Operations" on pages 28 through 45 of this report.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial statements and supplementary data are set forth on the pages indicated below.
Page
Independent Auditors' Report 47
Management's Report on Responsibility for Financial Statements 48
Financial Statements:
Consolidated Statement of Income for the Three Years Ended December 31, 1994 49 Consolidated Statement of Cash Flows for the Three Years Ended December 31, 1994 50 Consolidated Balance Sheet at December 31, 1994 and 1993 51 Consolidated Statement of Shareowners' Common Equity for the Three Years Ended December 31, 1994 53 Consolidated Statement of Preferred and Preference Stock at December 31, 1994 and 1993 53 Consolidated Statement of Long-Term Debt at December 31, 1994 and 1993 55 Notes to Financial Statements 56
Quarterly Financial, Common Stock Price and Dividend Data 90
Supplemental Financial Statement Schedule:
II - Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, 1994 91
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Based upon a recommendation of its Audit Committee, the Company's Board of Directors decided on January 25, 1995 that Deloitte & Touche LLP (Deloitte) would not be retained as the Company's independent auditors for 1995. On February 22, 1995, the Company's Board of Directors, based upon a recommendation of it's Audit Committee, appointed Price Waterhouse LLP as the Company's new independent auditors.
The auditors' reports of Deloitte on the Company's financial statements for each of the two most recent fiscal years reported upon, ending December 31, 1994, did not contain any adverse opinion or disclaimer of opinion, nor were the reports modified or qualified in any manner.
During the period of such two fiscal years and the period from December 31, 1994 through January 25, 1995, there were no disagreements with Deloitte on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure. During such periods, there were no "reportable events" as that term is defined in Item 304(a)(1)(v) of Regulation S-K.
Deloitte provided a letter to the Company regarding this matter, dated February 1, 1995, indicating that they agreed with the statements in the two preceding paragraphs.
(THIS PAGE LEFT BLANK INTENTIONALLY.)
REVIEW OF THE COMPANY'S FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Earnings
Earnings per share of common stock were $1.41 in 1994, $2.07 in 1993 and $2.02 in 1992.
Earnings for 1994 were adversely affected by several one-time charges, including two major charges, during the fourth quarter. One amounted to $75.9 million, or 28 cents per share of common stock, resulting from costs associated with a voluntary early retirement program, and the other amounted to $73.7 million, or 26 cents per share, from a write down in the carrying value of a subsidiary's investment in undeveloped coal reserves. In addition, two nonrecurring charges recorded earlier in the year reflected the disallowance by the Pennsylvania Public Utility Commission (PUC) of recovery of replacement power costs, incurred during an extended outage at the Susquehanna station, through the Energy Cost Rate (ECR) amounting to $15.7 million, or 6 cents per share of common stock, and a decision of the Commonwealth Court of Pennsylvania which reversed a PUC order that permitted deferral of the cost of postretirement benefits other than pensions. The Company charged the deferred postretirement benefit costs applicable to 1993 against income which amounted to $10.8 million or 4 cents per share. These matters are discussed in more detail in this review.
Although the nonrecurring charges depressed earnings in 1994, underlying sales performance was strong, with a 4.1% increase in sales to ultimate customers, due to improving economic conditions and colder-than- normal weather in the winter months. Other positive effects on earnings included the Company's continued efforts to control operating and maintenance costs, and refinancing higher cost securities to take advantage of favorable market conditions.
In 1993 increasing economic activity and the effects of hotter-than- normal weather in the summer were the primary causes for the earnings improvement over 1992. Earnings in 1993 also benefited from the Company's efforts to control costs and refinance higher cost securities. In 1993 the Company recorded charges against income that, in the aggregate, adversely affected earnings by about $31.5 million, or 12 cents per share, related to: (i) a settlement agreement with complainants against the Company's 1990-91 through 1993-94 ECRs; (ii) the write off of certain deferred retiree benefit costs; and (iii) the adoption of Statement of Financial Accounting Standards (SFAS) 112, "Employers' Accounting for Postemployment Benefits."
Electric Energy Sales
System, or service area, sales were 32.3 billion kwh in 1994, an increase of about 1.3 billion kwh, or 4.1%, over 1993. The extreme cold weather in the first quarter of 1994 and the continued increase in economic activity in Central Eastern Pennsylvania were the primary reasons for the increases in system sales. Sales in all major customer categories were higher in 1994 than in 1993. The higher system sales in 1994 followed an increase in 1993 system sales over 1992 of about 1.3 billion kwh that was due to increased economic activity in the service area and the effect of hotter summer weather resulting in higher air conditioner use. The Company estimates that if normal weather had been experienced in both years, system sales for 1994 would have increased by 1.1 billion kwh, or 3.5%, over 1993.
Actual sales to residential and commercial customers in 1994 increased 402 million kwh, or 3.6%, and 342 million kwh, or 3.6%, respectively, over 1993. The Company estimates that under normal weather conditions for both years, sales to residential and commercial customers in 1994 would have increased 243 million kwh, or 2.2%, and 327 million kwh, or 3.5%, respectively, over 1993.
Industrial sales, which are not affected by weather conditions, increased 437 million kwh in 1994, or 4.8%, over 1993. Industrial sales are an important indicator of the economic health of the Company's service area.
System sales in 1995 are currently forecasted to be approximately 32.5 billion kwh, an increase of 136 million kwh, or 0.4%, over 1994 system sales, and a 419 million kwh, or 1.3%, increase over 1994 weather- normalized sales.
Total electric energy sales, which include contractual sales to other major utilities and energy sales to Pennsylvania-New Jersey-Maryland Interconnection Association (PJM) utilities, were essentially unchanged during the 1992-1994 period.
Contractual sales to other major utilities include: (i) energy sold to Atlantic City Electric Company (Atlantic), Baltimore Gas & Electric Company (BG&E) and Jersey Central Power & Light Company (JCP&L) pursuant to long-term contracts under which these utilities purchase a specified percentage of the capacity and related energy from Company-owned generating units; and (ii) energy sold on a short-term basis to other electric utilities. Contractual sales to other major utilities were 6.3 billion kwh in 1994, or 11.7% lower than 1993, as a result of reduced output from the Company's coal-fired generating units. Contractual sales to other major utilities in 1993 were about 7.1 billion kwh, or 2.5% lower than 1992.
Sales to JCP&L will continue at the current level through 1995 and then begin to phase out in equal annual amounts during the remaining term of the agreement which ends in December 1999. Sales to Atlantic and BG&E continue through September 2000 and May 2001, respectively. In its pending rate case (see "Rate Matters"), the Company has proposed that the costs associated with the returning capacity be recovered through the ECR. If the PUC denies this request, the Company expects that any sales of the returning capacity and related energy under bulk power marketing conditions would be at prices less than those reflected in the existing agreements. PJM energy sales were about 3.2 billion kwh in 1994, or 23.7% lower than 1993. In 1993 PJM energy sales were about 4.1 billion kwh, or 19.7% lower than 1992. The decreases in both years were primarily due to increased system sales and a decrease in the output of the Company's generating units. In 1994 the decrease in output was primarily due to lower availability of the coal-fired units. The decrease of output in 1993 resulted from an increase in the availability of nuclear generating capacity of the other PJM utilities.
Capacity-Related and Transmission Entitlement Transactions
The Company's strong generating capacity position has enabled it to enter into a number of transactions with other electric utilities. These transactions include: (i) the sale of capacity credits but no energy to other utilities in the PJM to enable them to satisfy their PJM contractual capacity obligations; (ii) agreements with both PJM and non-PJM utilities for the reservation of output during certain periods from the Company's generating units, with the option to purchase energy from those units; and (iii) arrangements whereby other PJM utilities can purchase the Company's entitlements to use the PJM transmission system to import energy from utilities outside the PJM.
Revenues from the sale of capacity credits, the reservation of output from generating units and the sale of transmission entitlements, net of foregone PJM interchange savings which are included in the Company's ECR, totaled $28.7 million in 1994, $35.0 million in 1993 and $35.0 million in 1992. The 1994 revenues exclude approximately $8.4 million of receipts from installed capacity credit sales which were credited to customers through the ECR. The Company currently expects about $14.6 million of revenues from these transactions during 1995, exclusive of credits to be applied to the ECR.
The Company is continuing to look for opportunities to derive additional revenues from these transactions due to its strong generating capacity position. However, increased competition in capacity credit transactions has reduced the Company's share of this market and the unit price received for such sales. The amount of revenues from these transactions depends on many factors, and the Company cannot predict the amount of revenues it will ultimately realize from these transactions.
In October 1994, the PUC approved a settlement agreement resolving all complaints against the 1990-91 ECR through 1993-94 ECR including issues related to capacity-related transactions. The agreement provides, among other things, for crediting the 1994-95 ECR with a portion of the receipts from capacity credit sales. See "Rate Matters" below for additional information.
Rate Matters
Base Rate Filing with the PUC
In December 1994, the Company filed a request with the PUC for a $261 million increase in electric base rates, an 11.7% increase in PUC- jurisdictional rates. The PUC has decided to hold hearings and conduct an investigation of the request. A final rate decision is expected in late September 1995. A detailed discussion of the rate filing is presented in Financial Note 3.
Energy Cost Rate Issues
In April 1994, the PUC reduced the Company's 1994-95 ECR claim by approximately $15.7 million to reflect costs associated with replacement power during a portion of the time that Unit 1 of the Company's Susquehanna station was out of service for refueling and repairs. As a result of the PUC's action, the Company recorded a charge against income in the first quarter of 1994 for the $15.7 million of unrecovered replacement power costs. This charge adversely affected net income by about $9.0 million or 6 cents per share of common stock.
The Company filed a complaint with the PUC objecting to the decision to exclude these replacement power costs from the 1994-95 ECR and subsequently entered into a settlement agreement with the complainants and the Office of Trial Staff on this matter.
The PUC approved the settlement agreement on February 24, 1995. As a result of the PUC Order, the Company, in the first quarter of 1995, will record a credit to income of $9.7 million which would increase net income by about $5.5 million or 4 cents per share of common stock.
In October 1994, the PUC issued an order approving a settlement agreement the Company reached in January 1994 with the Office of Consumer Advocate (OCA) and certain industrial customers concerning the 1990-91 ECR through the 1993-94 ECR. The PUC order resolved all complaints against those ECRs, and required the Company to credit the 1994-95 ECR with a one- time adjustment for a portion of the receipts from installed capacity credit sales made from April 1990 through December 31, 1993 and also provided that about one-third of the receipts from installed capacity credit sales made after December 31, 1993 will be credited through future ECRs. These capacity credit sales are discussed in Financial Notes 3 and 4. The PUC order also provided that a portion of the PUC-jurisdictional amount of deferred retired miners' health care benefits costs, which the Company sought to recover through the ECR, will not be recoverable. As a result of this order, in the fourth quarter of 1993 the Company recorded a charge to expense of $17.1 million, which reduced 1993 net income by approximately $9.7 million or 6 cents per share of common stock.
Postretirement Benefits Other Than Pensions
In March 1993, the PUC approved the Company's petition to defer the increase in retiree benefits costs arising from adoption of SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." Under the PUC order, the increased costs applicable to PUC-jurisdictional customers would have been deferred from January 1, 1993 until such costs were included in customer rates in the Company's next retail base rate proceeding. Accounting rules permit deferral of the costs for about five years.
In May 1994, in response to an appeal by the OCA, the Commonwealth Court of Pennsylvania reversed the PUC order and held that the Company could not defer these costs.
As a result of the Court's decision, the Company began expensing the increased costs applicable to operations that would have otherwise been deferred and wrote off the costs that had been deferred from January 1, 1993. The charge to expense for 1994 amounted to $22.9 million, which included $10.8 million applicable to 1993. The Company is charging expense on a current basis for retiree benefits costs.
In June 1994, the PUC and the Company requested the Pennsylvania Supreme Court to hear an appeal of the Commonwealth Court decision.
FERC-Jurisdictional Rates
The Company has entered into five year sales contracts with certain small utilities the Company currently serves, which reduced rates to these small utilities by about $3.3 million in 1994 and will reduce rates by about an additional $4.1 million in 1996. In connection with these agreements, in the fourth quarter of 1993 the Company wrote off the deferred portions of retired miners' health care benefits costs and postretirement benefits other than pensions applicable to FERC- jurisdictional customers. The charge to expense amounted to $8.9 million, which reduced 1993 net income by $5.1 million or 3 cents per share of common stock.
Operating Revenues
Total operating revenues in 1994 decreased $1.9 million, or 0.1%, from 1993. Revenues from energy sales to ultimate customers in 1994 increased $44.7 million over 1993 due to higher customer usage and recoverable fuel and energy costs. These increases were principally offset by: (i) lower sales to other major utilities, $13.3 million; (ii) lower sales on the PJM, $21.1 million; and (iii) unrecovered replacement power costs, $15.7 million as discussed in "Rate Matters." Operating revenues for 1993 decreased $17.1 million, or 0.6%, from 1992. Changes in 1993 operating revenues from 1992 principally included: (i) revenues from sales to ultimate customers increased $18.4 million; (ii) sales to other major utilities decreased $16.4 million; and (iii) PJM sales decreased $14.8 million.
Tariffs subject to PUC-jurisdiction accounted for approximately 83% of the Company's revenues from energy sales in 1994. The remaining 17% of such revenues resulted from sales regulated by the FERC and include the Company's PJM energy sales.
Billings to customers under PUC jurisdiction include: (i) base rate charges; (ii) the ECR which is a supplemental charge or credit for fuel and other energy costs over or under the levels included in base rates; (iii) a State Tax Adjustment Surcharge (STAS) which adjusts retail customers' bills for the effects of changes in state tax rates; and (iv) a Special Base Rate Credit Adjustment (SBRCA) that flows through to customers the effects of certain nonrecurring items.
Billings to utilities are subject to FERC jurisdiction. In the case of certain small utilities, billings include base rate charges and a supplemental charge or credit for fuel costs over or under the levels included in base rates. The FERC also regulates contractual sales to other major utilities, PJM energy sales and capacity-related and transmission entitlement transactions. Sales to Atlantic, BG&E and JCP&L are made at a price covering the Company's cost of service, including a return on investment.
Energy sales relating to the reservation of output from the Company's generating units are generally made at a price equal to the cost of fuel plus an amount to reflect foregone interchange savings. PJM energy sales are made at a price equal to the midpoint between the sellers' actual costs and costs that the buyers would have incurred to produce the energy. Capacity-related and transmission entitlement transactions are made at prices negotiated by the Company and the purchaser, subject to a price cap accepted by the FERC.
Fuel Expense
Fuel expense for 1994 and 1993 decreased by $33.3 million and $49.5 million, respectively, from the prior year. These decreases excluded the write off of $11 million of deferred retired miners' health care benefits in 1993 and a related credit to expense of $3.6 million in 1994. The decrease in 1994 was primarily due to lower availability of coal-fired generation which resulted in reduced sales to PJM and other major utilities. Lower fuel costs for off-system sales were partially offset by higher cost oil-fired generation for base load during the first quarter of 1994. The decrease in 1993 was primarily due to lower unit fuel costs for coal-fired generation, partially offset by higher oil-fired generation. For 1993, the cost of coal delivered to the Company's generating stations declined to $36.23 per ton from $41.44 per ton for 1992.
Spent Nuclear Fuel
The U.S. Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel removed from nuclear reactors. The Company currently pays DOE a fee for future disposal services and recovers such costs in customer rates.
Delays in opening a federal permanent storage facility will require the Company to provide interim storage for spent fuel at the Susquehanna station beginning in 1997 until at least 2010.
Power Purchases
In 1994, power purchases were $287.3 million, an increase of $8.5 million over 1993. Power purchases were $278.8 million in 1993, an increase of $3.3 million over 1992. The increases were due to greater quantities of power purchased from PJM and other utilities, partially offset by lower power purchases from non-utility generators.
Other Operation, Maintenance and Depreciation
The increase in other operation expenses in 1994 compared to 1993 is primarily the result of the Commonwealth Court of Pennsylvania decision reversing the PUC order regarding the deferral of postretirement benefits costs other than pensions. See "Rate Matters" for further discussion.
In 1993 the Company wrote off $9.1 million of obsolete and excess materials and supplies at its fossil-fueled steam generating stations. Of this amount, $2.2 million was charged to other operation expense and $6.9 million was charged to maintenance expense.
The amortization of the deferred income effect of adopting the inventory method of accounting for power plant spare parts is credited to maintenance expense on the Consolidated Statement of Income. This amortization amounted to $24.7 million in 1994, $24.3 million in 1993, and $23.5 million in 1992. Excluding the credits associated with power plant spare parts and the 1993 accrual for the recognition of obsolete and excess materials and supplies, maintenance expense decreased by $5.9 million, or 2.8% in 1994 compared to 1993. A similar comparison of 1993 to 1992 indicated a $14.1 million, or 6.3%, decrease. The reduction in maintenance expense resulted primarily from lower costs associated with maintaining the Company's generating stations.
Higher depreciation expense reflects the annual increase associated with the method of depreciating the Susquehanna station and the depreciation of new property, plant and equipment placed in service. As approved by the PUC and the FERC, depreciation expense for the Susquehanna station will increase annually through the year 1998. In 1993 and 1994, the amount of depreciation expense applicable to the Susquehanna station exceeded the amount that would have been recorded using the straight-line method, resulting in an amortization of previously deferred depreciation. Beginning in 1999, depreciation is scheduled to change to the straight-line method at a level substantially less than the amount expected to be recorded in 1998. The amount of depreciation applicable to that portion of the Susquehanna station subject to an annual increase in the amount of depreciation was $128 million in 1994 and $116 million in 1993, and will increase annually to $192 million in 1998 and then decline to $102 million in 1999. Proposed changes to the Company's current depreciation methods were included in the December 1994 base rate filing with the PUC. See Financial Note 3.
For a discussion of the Company's efforts to continue to reduce costs, see "Increasing Competition" on page 42.
Taxes
In June 1994, Pennsylvania enacted legislation that decreased the Company's state corporate net income tax rate from 12.25% to 11.99% retroactive to January 1, 1994 with further reductions to 10.99%, 10.75% and 9.99% in 1995, 1996 and 1997, respectively. This resulted in a decrease of $0.8 million in income tax expense for 1994. Substantially all of this amount was reflected in lower customer rates through the STAS beginning in July 1994.
In August 1993, the Omnibus Budget Reconciliation Act of 1993 was enacted, which contained a provision that increased the Company's federal income tax rate from 34% to 35% retroactive to January 1, 1993. This higher tax rate increased the Company's federal income tax expense for 1993 by $5.9 million.
Financing Costs
The Company continued in 1994 to take advantage of opportunities to reduce its financing costs by retiring long-term debt and preferred stock with the proceeds from the sales of securities at a lower cost. Interest on long-term debt and dividends on preferred and preference stock decreased by $34 million from $277 million in 1991 to $243 million in 1994.
Financial Condition
Capital Expenditure Requirements
The schedule below shows the Company's actual capital expenditures for electric utility operations for the years 1992-1994 and current projections for the years 1995-1997. Construction expenditures during the years 1992- 1994 totaled about $1.3 billion and are expected to be at the same level during the years 1995-1997.
Capital Expenditure Requirements (a)
------Actual------ ----Projected---- 1992 1993 1994 1995 1996 1997 (Millions of Dollars) Construction expenditures Generating facilities $136 $142 $152 $111 $107 $ 99 Transmission and distribution facilities 186 173 170 166 159 165
Environmental 13 65 94 40 52 156 Other 52 51 58 70 83 58 387 431 474 387 401 478 Nuclear fuel owned and leased 42 64 35 54 79 49 Other leased property 20 20 25 39 31 22 Total $449 $515 $534 $480 $511 $549
(a) Capital expenditure plans are revised from time to time to reflect changes in conditions. Actual expenditures may vary from those projected because of changes in plans, cost fluctuations, environmental regulations and other factors. Construction expenditures include Allowance for Funds Used During Construction (AFUDC) which is expected to be less than $25 million in each of the years 1995-1997.
Financing and Liquidity
Net cash provided by operating activities in 1994 decreased by $58.7 million primarily due to lower earnings, increases in income tax payments, higher fuel inventories and a reduction in accounts payable. Cash provided by operating activities in 1993 and 1992 were essentially unchanged.
Net cash used in investing activities was $78.7 million higher in 1994 than 1993 and $25.6 million higher in 1993 than in 1992. The increase in 1994 was due to higher construction expenditures and an increase in financial investments by a subsidiary of the Company. The increase in investing activities in 1993 was due to higher construction expenditures.
For the years 1992-1994, the Company issued $2.16 billion of long-term debt, $380 million of preferred stock and about $83 million of common stock. Proceeds from security sales were used to retire about $1.8 billion of long-term debt and about $500 million of preferred and preference stock to lower the Company's financing costs, to reduce short-term debt and to finance construction expenditures. During the years 1992-1994, the Company also incurred $211 million of obligations under capital leases (primarily nuclear fuel). In 1994, the Company sold $919 million principal amount of first mortgage bonds and $80 million of preferred stock and issued $70 million of common stock of which $63 million was issued through its Dividend Reinvestment Plan (DRIP) and the remaining $7 million issued to the Employee Stock Ownership Plan. During the year, the Company retired $637 million of long-term debt, $120 million of preferred stock and decreased its short-term debt by $128 million.
After the payment of dividends, internally generated funds during the years 1995-1997 are expected to provide approximately 70-85% of the Company's construction expenditures which are expected to be $1.3 billion.
Sales of securities will be undertaken during the 1995-1997 period as needed to meet the Company's capital requirements, to meet a total of $211 million of long-term debt maturities and to provide funds for the early retirement of high cost securities if such retirements are determined to be appropriate in the light of market conditions and other factors. The Company expects to issue $180 million of common stock in 1995 through its DRIP and a public sale of common stock. In addition, the Company expects to arrange for the refinancing of $55 million of higher cost tax-exempt securities issued to provide pollution control and solid waste disposal facilities at the Company's generating stations.
The Company's ability to issue securities during the 1995-1997 period is not expected to be limited by earnings or other issuance tests. To enhance financing flexibility, a $250 million revolving credit arrangement is maintained with a group of banks and is used principally as a back-up for the Company's commercial paper and $45 million in credit arrangements are maintained with a group of banks to provide back-up for the Company's commercial paper and short-term borrowings of certain subsidiaries. No borrowings were outstanding at December 31, 1994 under these arrangements.
Allowance for Funds Used During Construction
The AFUDC, a non-cash credit to income, accounted for about 6.1% of earnings in 1994. The amount of AFUDC recorded will depend on the timing and level of construction work in progress as well as the rate treatment afforded the capital expenditures required to comply with the clean air legislation. Under current Pennsylvania law, construction work in progress for certain non-revenue producing assets, such as capital expenditures for pollution control equipment, can be claimed in rate base.
Financial Indicators
Due to one-time charges to income in 1994, several financial indicators decreased from 1993. The Company earned an 8.73% return on average common equity during 1994, down from the 13.06% earned in 1993. The ratio of the Company's pre-tax income to interest charges decreased from 3.3 in 1993 to 2.7 in 1994. Excluding these one-time charges, the return on average common equity and the ratio of pre-tax income to interest charges in 1994 would have been 12.53% and 3.1, respectively. See "Earnings" on page 28. The Company increased common stock dividends from an annual per share rate of $1.65 in 1993 to $1.67 in 1994. The book value per share of common stock decreased 1.0% from $15.95 at the end of 1993 to $15.79 at the end of 1994. The ratio of the market price to book value of common stock was 120% at the end of 1994 compared with 169% at the end of 1993.
Clean Air Legislation and Other Environmental Matters
The Federal Clean Air Act Amendments of 1990 deal, in part, with acid rain under Title IV, attainment of federal ambient ozone standards under Title I, and toxic air emissions under Title III. The acid rain provisions specify Phase I sulfur dioxide emission limits for about 55% of the Company's coal-fired generating capacity by January 1995, and more stringent Phase II sulfur dioxide emission limits for all of the Company's fossil-fueled generating units by January 2000.
The Company's capital costs of compliance with the Phase I requirements under Title IV are included in the table of "Capital Expenditure Requirements" on page 35. The Company may also incur operating expenses not reflected therein, and may choose to limit the generation of certain units and to bank or trade emission allowances among its generating units or with other utilities, to the extent permitted by the legislation.
To meet the Phase II acid rain sulfur dioxide emission standards, the Company may install flue gas desulfurization equipment (FGD) on up to 60% of its coal-fired generating capacity, purchase lower sulfur coal, and bank or trade emission allowances among its generating units or with other utilities to the extent permitted by the legislation. The exact mix of lower sulfur fuel, emission allowance purchases, sales or trades, and the amount and timing of FGD will be based on FGD installation costs, fuel cost and availability and emission allowance prices.
The ambient ozone attainment provisions contained in Title I of the legislation require all major stationary sources within the Northeast Ozone Transport Region (which includes all of Pennsylvania) to install reasonably available control technology (RACT) for nitrogen oxides emissions by May 1995. The Company has complied with this requirement. The associated capital costs are included in the table of "Capital Expenditure Requirements" on page 35.
Further ozone reductions may be required as a result of modeling of nitrogen oxides and volatile organic compounds emissions in the Northeast Ozone Transport Region. A two-phase nitrogen oxides reduction from pre- Clean Air Act levels has been proposed for the area where the Company's plants are located -- a 55% reduction by May 1999 and a 75% reduction by 2003 -- unless scientific studies to be completed by 1997 indicate a different reduction. The reductions would be required during a five-month ozone season from May through September.
In addition to acid rain and ambient ozone attainment provisions, the legislation requires the Environmental Protection Agency (EPA) to conduct a study of hazardous air emissions from power plants. EPA is also studying the health effects of fine particulates which are emitted from power plants and other sources. Adverse findings from either study could cause the EPA to mandate additional ultra high efficiency particulate removal baghouses or specialized flue gas scrubbing to remove certain vaporous trace metals and certain gaseous emissions.
In addition to the "Capital Expenditure Requirements" shown on page 35, the Company currently estimates that additional capital expenditures and operating costs for environmental compliance will be incurred beyond 1997. Capital expenditures that may be required and the additional revenue required to recover these costs, based on 1994 revenues, are as follows: Capital Cost Revenue ($ millions) Requirement Phase II acid rain 1998-2005 $300-500 3.0% Nitrogen oxides and ambient ozone by: 1999 80 0.5% 2003 150 1.3% Hazardous air emissions by 2000 310 1.8%
Collectively, these costs represent a potential capital exposure of up to $1.0 billion beyond 1997, as well as additional operating costs in amounts which are not now determinable but could be material.
The Pennsylvania Air Pollution Control Act implements the Federal Clean Air Act Amendments of 1990. The state legislation essentially requires that new state air emission standards be no more stringent than federal standards. This legislation has no effect on the Company's plans for compliance with the Federal Clean Air Act Amendments of 1990.
The PUC's policy regarding the trading and usage of, and the ratemaking treatment for, emission allowances by Pennsylvania electric utilities provides, among other things, that the PUC will not require approval of specific transactions and the cost of allowances will be recognized as energy-related power production expenses and recoverable through the ECR.
The Pennsylvania Department of Environmental Resources (DER) regulations governing the handling and disposal of industrial (or residual) solid waste require the Company to submit detailed information on waste generation, minimization and disposal practices. They also require the Company to upgrade and repermit existing ash basins at all of its coal- fired generating stations by applying updated standards for waste disposal. Ash basins that cannot be repermitted are required to close by July 1997. Any groundwater contamination caused by the basins must also be addressed. Any new ash disposal facility must meet the rigid site and design standards set forth in the regulations. In addition, the siting of future facilities at Company facilities could be affected.
To address the DER regulations, the Company plans to install dry fly ash handling systems at the Brunner Island, Sunbury and Holtwood stations. The Company, with siting assistance from a public advisory group, has chosen mine sites at which to use the dry fly ash from the Sunbury and Holtwood stations for reclamation. In addition, the Company is exploring opportunities to beneficially use coal ash from Brunner Island in various roadway construction projects in the vicinity of the plant that may delay or preclude the need for a new disposal facility.
Groundwater degradation related to fuel oil leakage from underground facilities and seepage from coal refuse disposal areas and coal storage piles has been identified at several Company generating stations. Many requirements of the DER regulations address these groundwater degradation issues. The Company has reviewed its remedial action plans with the DER. Remedial work is substantially completed at one generating station, and remedial work may be required at others.
The DER regulations to implement the toxic control provisions of the Federal Water Quality Act of 1987 and to advance Pennsylvania's toxic control program authorize the DER to use both biomonitoring and a water quality based chemical-specific approach in the National Pollutant Discharge Elimination System (NPDES) permits to control toxics. In 1993, the Company received new NPDES permits for the Montour and Holtwood stations. The Montour permit contains very stringent limits for certain toxic metals and increased monitoring requirements. More toxic reduction studies will be conducted at Montour before the permit limits become effective. Additional water treatment facilities may be needed at Montour, depending on the results of the studies.
At Holtwood, toxics are required to be monitored at the fly ash basin until its closure in 1997. No limits have been set at this time. The Company will therefore comply with an implementation schedule for such closure and for construction of a new dry fly ash handling system at Holtwood. The closure of the Holtwood fly ash basin will require changes to the facility's existing waste water treatment system. Improvements and upgrades are being planned for the Sunbury and Brunner Island waste water treatment systems to meet the anticipated permit requirements.
Capital expenditures through 1997, to comply with the residual waste regulations, correct groundwater degradation at fossil-fueled generating stations and address waste water control at Company facilities, are included in the "Capital Expenditure Requirements" on page 35. The Company currently estimates that about $77 million of additional capital expenditures could be required beyond 1997. Actions taken to correct groundwater degradation, to comply with the DER's regulations and to address waste water control are also expected to result in increased operating costs in amounts which are not now determinable but could be material.
The Company has been discussing with the DER the issue of potential polychlorinated biphenyl (PCB) contamination at certain of the Company's substations and pole sites. In addition, the Company at one time owned and operated a number of coal gas manufacturing facilities, all of which were later sold. During their operation, these gas plants produced waste byproducts, some amount of which may still remain at the plant sites. Also, oil and/or other contamination may exist at some of the Company's former generating facilities. As a current or past owner/operator of these sites, the Company may be liable under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (Superfund), or other laws for the costs associated with addressing any hazardous substances at these sites.
In early 1995 the Company expects to finalize a negotiated Consent Order with the DER to address a number of these sites where remediation may be necessary or desirable. The sites will be prioritized based upon a number of factors, including any human health or environmental risk posed by the site, the public's interest in the site, and the Company's plans for the site. Under the Consent Order, the Company will not be required by DER to spend more than $5 million per year on investigation and remediation at those sites covered by the Consent Order.
At December 31, 1994, the Company had accrued $8.3 million, representing the amount the Company can reasonably estimate it will have to spend to remediate sites involving the removal of hazardous or toxic substances including those covered by the Consent Order mentioned above. The Company is involved in several other sites where it may be required, along with other parties, to contribute to such remediation. Some of these sites have been listed by the EPA under Superfund, and others may be candidates for listing at a future date. Future cleanup or remediation work at sites currently under review, or at sites currently unknown, may result in material additional operating costs which the Company cannot estimate at this time. In addition, certain federal and state statutes, including Superfund and the Pennsylvania Hazardous Sites Cleanup Act, empower certain governmental agencies, such as the EPA and the DER, to seek compensation from the responsible parties for the lost value of damaged natural resources. The EPA and the DER may file such compensation claims against the parties, including the Company, held responsible for cleanup of such sites. Such natural resource damage claims against the Company could result in material additional liabilities.
Concerns have been expressed by some members of the scientific community and others regarding the potential health effects of electric and magnetic fields (EMF). These fields are emitted by all devices carrying electricity, including electric transmission and distribution lines and substation equipment. Federal, state and local officials are focusing increased attention on this issue. The Company is actively participating in the current research effort to determine whether or not EMF causes any human health problems and is taking steps to reduce EMF, where practical, in the design of new transmission and distribution facilities. The Company is unable to predict what effect the EMF issue might have on Company operations and facilities.
In complying with statutes, regulations and actions by regulatory bodies involving environmental matters, including the areas of water and air quality, hazardous and solid waste handling and disposal and toxic substances, the Company may be required to modify, replace or cease operating certain of its facilities. The Company may also incur material capital expenditures and operating expenses in amounts which are not now determinable.
Uranium Enrichment Decontamination and Decommissioning Fund
The Energy Policy Act of 1992 (Energy Act) established the Uranium Enrichment Decontamination and Decommissioning Fund (Fund) and provides for an assessment on domestic utilities with nuclear power operations, including the Company. Assessments are based on the amount of uranium a utility had processed for enrichment prior to enactment of the Energy Act and are expected to be paid to the Fund by such utilities over a 15-year period. Amounts paid to the Fund are to be used for the ultimate decontamination and decommissioning of the Department of Energy's uranium enrichment facilities. The Energy Act states that the assessment shall be deemed a necessary and reasonable current cost of fuel and shall be fully recoverable in rates in all jurisdictions in the same manner as the utility's other fuel costs.
As of December 31, 1994, the Company's recorded liability for its total assessment amounted to about $31.5 million. The liability is subject to adjustment for inflation. The corresponding charge to expense was deferred because the Company includes its annual payments to the Fund in the ECR which is in the Company's PUC tariffs and in the fuel adjustment clause which is in the Company's FERC tariffs. As a result, the assessment does not affect net income.
Postretirement Benefits Other Than Pensions and Postemployment Benefits
In January 1993, the Company adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." SFAS 106 establishes new rules for accounting for the costs of postretirement benefits other than pensions. The statement requires accrual, during the years that the employees render the necessary service, of the expected cost of providing those benefits. Caps have been established on the amount the Company will pay for retiree health care costs for all employees who retire after March 1993. See "Rate Matters" on page 13 for additional information on postretirement benefit issues.
The Company provides health and life insurance benefits to disabled employees and income benefits to eligible spouses of deceased employees. In December 1993, the Company adopted SFAS 112, "Employers' Accounting for Postemployment Benefits," which requires the Company to accrue, during the years that the employees render the necessary service, the expected cost of providing benefits to former or inactive employees after employment but before retirement. The adoption of SFAS 112 did not have a material effect on the Company's net income. Postemployment benefits charged to operating expenses were $2.1 million, $6.5 million and $1.0 million for 1994, 1993 and 1992, respectively.
Write Down of Coal Reserves
In connection with a review by the Company of its non-core business assets performed in 1994, a subsidiary of the Company initiated an evaluation of the carrying value of its $83.5 million investment in undeveloped coal reserves in western Pennsylvania. The Company had acquired these reserves in 1974 through the subsidiary with the intent to supply future coal-fired generating stations. The Company has concluded that it would not develop such reserves as a source of fuel for its generating stations.
This evaluation of the carrying value of the subsidiary's investment in such reserves was completed by outside appraisal firms and indicated that an impairment had occurred. Accordingly, the carrying value of this investment was written down to its estimated net realizable value of $9.8 million. This write down resulted in an after-tax charge to income of $40 million in the fourth quarter of 1994, which reduced 1994 earnings by approximately 26 cents per share of common stock.
Increasing Competition
The electric utility industry, including the Company, has experienced and will continue to experience a significant increase in the level of competition in the energy supply market. The Energy Act is having a significant impact on the Company and the electric utility industry, primarily through amendments to the Public Utility Holding Company Act of 1935 (PUHCA) that create a new class of independent power producers, and amendments to the Federal Power Act that open access to electric transmission systems for wholesale transactions. In response to this increased competition, the Company has undertaken strategic initiatives to strengthen its position in the market.
Market Initiatives
The Company entered into new five-year supply agreements at reduced prices with its existing wholesale customers. In addition, the Company is actively participating in negotiations and proceedings involving the sale of electricity to wholesale customers currently served by other electric utilities. These wholesale customers are generally small utilities that do not have their own generating capability and purchase electricity from others.
While there is currently no comparable competition in the retail electric market, the Company anticipates that it will face similar competitive pressures in the industrial and large commercial sectors of that market in the future.
The Company has received PUC approval to enter into negotiated rates ("flexible rates") with certain industrial and commercial customers and also provide real time pricing rates on a three-year experimental basis to certain industrial and commercial customers. The flexible rate initiative will enable the Company to negotiate rates with new and existing commercial and industrial customers that have competitive alternatives to purchasing electricity from the Company. Rates could be negotiated between a ceiling of full costs and a floor of variable costs of production. The real time pricing initiative will enable the Company to offer to large commercial and industrial customers rates based upon the Company's hourly cost of generation. The Company will select a maximum of 25 large industrial customers to participate in the real time pricing project.
As the electric utility industry moves toward increased competition, the Company has developed initiatives that would make its steam electric stations more efficient and better able to compete in an environment of market-based pricing of electricity. Included in the proposed initiatives are measures to decrease annual operation and maintenance costs and reduce capital expenditures. In addition, the Company has developed initiatives to achieve longer refueling cycles, reduce the duration of refueling outages and reduce costs at the Susquehanna station.
Restructuring
The Company also has initiated a restructuring of its utility operations, to better position itself for the competitive future. The organization moved from a geographic to a functional organization and physical workers were consolidated in a new mobile work force. The new organization replaces the Company's five geographic operating divisions with three new departments, based on services provided to customers. Electrical Systems is responsible for designing, maintaining and operating the facilities that transmit and deliver electricity to customers; Customer Services is responsible for customer inquiries and billing; and Marketing and Economic Development is responsible for marketing electric heat and other applications to residential customers, providing energy services to industrial and commercial customers, and community activities.
Ongoing department-level re-engineering efforts are expected to continue to impact the size of the Company's workforce. The redesigned work is expected to require fewer employees. Although no specific targets have been set, the Company currently expects that employment levels may decline to the 6,000 to 6,500 level over the next three years. The Company may incur additional costs as a result of these workforce reductions.
Voluntary Early Retirement Program
In conjunction with the announcement of the corporate restructuring, the Company offered a voluntary early retirement program to 851 employees who were age 55 or older by December 31, 1994. A total of 640 employees elected to retire under the program, at a total cost of $75.9 million. Prior to the early retirement program, the Company had about 7,600 employees. The early retirement program provided for a lump sum payment based on an employee's years of service, no reduction in retirement benefits for age and supplemental monthly payments. The Company recorded the cost of the program as a one-time charge in the fourth quarter of 1994, which, after income taxes, reduced net income by $43.4 million, or 28 cents per share of common stock. A portion of the costs applicable to the voluntary early retirement program will be recovered through power contract billings. Annual savings in operating expenses associated with this reduction in employees are estimated to be approximately $35 million.
The Company's PUC base rate filing reflects an estimate of the savings from the early retirement program and seeks recovery of the cost of the program over a five-year period. To the extent that the PUC permits recovery of the cost of the program in rates, the Company will record a credit to income to recognize the income effect related to the recoverable portion of the charge recorded in 1994.
New Markets
The Company's strategic initiatives also include an assessment of entering power-related businesses outside of the Company's service territory, both domestically and in foreign countries. Any expansion by the Company into these areas would be methodical and deliberate. To take advantage of these new business opportunities, the Company has decided to pursue the formation of a holding company structure, subject to the receipt of appropriate regulatory approvals and, ultimately, shareowner approval at the 1995 annual meeting.
In March 1994, the Company incorporated a new subsidiary, Power Markets Development Company (PMD), and made an initial investment of $50 million in this new subsidiary. PMD will help the Company take advantage of new opportunities in the building and operation of power plants in North America and elsewhere. Other subsidiaries will be formed to take advantage of new business opportunities.
In connection with the formation of the holding company structure, the Company filed the requisite applications for approval with the PUC, the FERC, the Securities and Exchange Commission (SEC) and the Nuclear Regulatory Commission (NRC). The FERC, the NRC and the PUC approvals have been obtained, while the SEC application remains pending. The PUC approval is subject to certain conditions, which are not expected to materially restrict the Company's entry into unregulated business activities.
Regulatory Developments
In light of the increased competition in the electric utility market, in June 1994 FERC issued a Notice of Proposed Rulemaking (NOPR) regarding recovery of stranded costs. In general, the FERC has proposed that utilities should address stranded cost recovery in all of their contracts with wholesale customers and that the states should address the issue of retail stranded costs. The NOPR also provides different treatment for stranded costs related to wholesale contracts which were existing prior to the date of the proposed rule and those executed after that date. The proposed rule defines wholesale stranded costs as "....any legitimate, prudent and verifiable costs incurred by a public utility or a transmitting utility to provide service to a wholesale requirements customer that subsequently becomes, in whole or in part, an unbundled transmission services customer of that public utility or transmitting utility." For contracts executed after the date of the proposed rule, utilities will not be allowed to seek recovery of stranded costs except through explicit stranded cost provisions, such as exit fee provisions, contained in their contracts and may not seek recovery of stranded costs through any transmission rates. For contracts executed prior to the date of issuance of the proposed rule, the FERC has proposed a three-year transition period in which utilities are required to renegotiate their wholesale requirements contracts which do not already contain stranded cost provisions, to include such provisions. The NOPR also provides guidance on the conditions a utility must demonstrate to the FERC in order to be allowed recovery of stranded costs.
In addition, in May 1994 the PUC ordered an investigation to examine the role of competition in Pennsylvania's electric utility industry. The investigation will allow the PUC to solicit input regarding the potential impact of competition on the state's electric utilities and their customers. The investigation, which will gather and analyze data at both the wholesale and retail levels of the electric utility industry, will be a paper proceeding conducted over approximately one year. Interested parties have the opportunity to file written comments addressing the following specific topics: wheeling - issues and impact, consumer issues, safety and reliability, the impact of market structure changes and legal issues.
The Company has submitted comments in response to both the FERC NOPR and the PUC order.
With respect to stranded costs, the Company has three general categories of costs whose recovery may depend to a large degree on the transition rules established to introduce increased competition in the industry. One category is the investment in utility plant, principally generating facilities, that might not be fully recoverable if electricity is based on market pricing. The second category consists of regulatory assets, or costs that have been deferred, whose recovery is based solely on continued cost-based rate regulation. The third category represents purchase power agreements where the price being paid may exceed the market price for electricity.
The Company has exposure to each of these categories of potential stranded costs to varying degrees and may not be able to fully recover them if the price of electricity is no longer subject to cost-based rate regulation. However, the Company cannot predict to what extent, if any, it may not be able to fully recover its costs if the price of electricity is no longer subject to cost-based rate regulation.
Independent Auditors' Report
Deloitte & Touche
Pennsylvania Power & Light Company:
We have audited the accompanying consolidated balance sheets and statements of preferred and preference stock and long-term debt of Pennsylvania Power & Light Company and its subsidiaries as of December 31, 1994 and 1993, and the related consolidated statements of income, shareowners' common equity, and cash flows for each of the three years in the period ended December 31, 1994. Our audits also included the financial statement schedules listed in the Index at Item 8 and in the Exhibit Index as Exhibit 99. These financial statements and the financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Pennsylvania Power & Light 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. Also, in our opinion, the financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
As discussed in Note 7 to the consolidated financial statements, in 1994 the Company changed its method of accounting for certain investments in debt and equity securities to conform with Statement of Financial Accounting Standards Number 115.
(Signed) Deloitte & Touche Parsippany, New Jersey February 3, 1994
Management's Report on Responsibility for Financial Statements
The management of Pennsylvania Power & Light Company is responsible for the preparation, integrity and objectivity of the consolidated financial statements and all other sections of this annual report. The financial statements were prepared in accordance with generally accepted accounting principles and the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission. In preparing the financial statements, management makes informed estimates and judgments of the expected effects of events and transactions based upon currently available facts and circumstances. Management believes that the financial statements are free of material misstatement and present fairly the financial position, results of operations and cash flows of the Company.
The Company's consolidated financial statements have been audited by Deloitte & Touche LLP (Deloitte), independent certified public accountants, whose report with respect to the financial statements appears on page 47. Deloitte's appointment as auditors was previously ratified by the shareowners. Management has made available to Deloitte all the Company's financial records and related data, as well as the minutes of shareowners' and directors' meetings. Management believes that all representations made to Deloitte during its audit were valid and appropriate.
The Company maintains a system of internal control designed to provide reasonable, but not absolute, assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition and the prevention and detection of fraudulent financial reporting. The concept of reasonable assurance recognizes that the cost of a system of internal control should not exceed the benefits derived and that there are inherent limitations in the effectiveness of any system of internal control.
Fundamental to the control system is the selection and training of qualified personnel, an organizational structure that provides appropriate segregation of duties, the utilization of written policies and procedures and the continual monitoring of the system for compliance. In addition, the Company maintains an internal auditing program to evaluate the Company's system of internal control for adequacy, application and compliance. Management considers the internal auditors' and Deloitte's recommendations concerning its system of internal control and has taken actions which are believed to be cost-effective in the circumstances to respond appropriately to these recommendations. Management believes that the Company's system of internal control is adequate to accomplish the objectives discussed in this report.
The Board of Directors, acting through its Audit Committee, oversees management's responsibilities in the preparation of the financial statements. In performing this function, the Audit Committee, which is composed of five independent directors, meets periodically with management, the internal auditors and the independent certified public accountants to review the work of each. The independent certified public accountants and the internal auditors have free access to the Audit Committee and to the Board of Directors, without management present, to discuss internal accounting control, auditing and financial reporting matters.
Management also recognizes its responsibility for fostering a strong ethical climate so that the Company's affairs are conducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the Company's Standards of Integrity, which is publicized throughout the Company. The Standards of Integrity addresses: the necessity of ensuring open communication within the Company; potential conflicts of interest; proper procurement activities; compliance with all applicable laws, including those relating to financial disclosure; and the confidentiality of proprietary information. The Company maintains a systematic program to assess compliance with these policies.
(signed) William F. Hecht
William F. Hecht Chairman, President and Chief Executive Officer
(signed) R. E. Hill
R. E. Hill Senior Vice President - Financial
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Accounting Records
	Accounting records for utility operations are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and adopted by the Pennsylvania Public Utility Commission (PUC).
Regulation
	The Company prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS 71 requires a rate-regulated entity to reflect the effects of regulatory decisions in its financial statements. In accordance with SFAS 71, the Company has deferred certain costs pursuant to the rate actions of the PUC and the FERC and is recovering or expects to recover such costs in electric rates charged to customers. These deferred costs or "regulatory assets" are enumerated and discussed in Note 9.
	The Company's base rate filing with the PUC discussed in Note 3 includes claims for recovery of certain of these costs. To the extent that the Company concludes that recovery of a regulatory asset is no longer probable, due to regulatory treatment, the effects of competition or other factors, the amount would have to be written off against income.
Principles of Consolidation
	All wholly owned subsidiaries (principally involved in oil pipeline operations, conducting unregulated business activities, passive financial investments and holding coal reserves) have been consolidated in the accompanying financial statements and all significant intercompany transactions have been eliminated. Income and expenses of subsidiaries not related to utility operations have been classified under other income and deductions on the Consolidated Statement of Income.
	The investment in Safe Harbor Water Power Corporation (Safe Harbor), of which the Company owns one-third of the outstanding capital stock representing one-half of the voting securities, is recorded using the equity method of accounting. The Company's principal transaction with Safe Harbor is the purchase of electricity amounting to (millions of dollars): 1994, $9.6; 1993, $9.9 and 1992, $9.4. Under equity accounting, the operations of Safe Harbor resulted in additional income to the Company of (millions of dollars): 1994, $2.2; 1993, $2.1 and 1992, $2.1.
Utility Plant and Depreciation
	Additions to utility plant and replacement of units of property are capitalized at cost. The cost of units of property retired or replaced is removed from utility plant accounts and charged to accumulated depreciation. Expenditures for maintenance and repairs of property and the cost of replacing items determined to be less than units of property are charged to operating expense.
	For financial statement purposes, depreciation is being provided over the estimated useful lives of property and is computed using a straight- line method for all property except for property placed in service prior to January 1, 1989 at the nuclear-fueled Susquehanna steam electric station. Current PUC and FERC rate orders provide for an increasing amount of annual depreciation for property placed in service prior to January 1, 1989 at the Susquehanna station through 1998, at which time depreciation will change to the straight-line method. Provisions for depreciation, as a percent of average depreciable property, approximated 3.5% in 1994, 3.3% in 1993 and 3.2% in 1992.
Utility Plant Carrying Charges
	Carrying charge accruals on certain facilities for the Susquehanna and Martins Creek stations are recorded as deferred debits in accordance with a FERC order. These amounts are being amortized to expense over the remaining lives of the stations.
Nuclear Decommissioning and Fuel Disposal
	An annual provision for the Company's share of the future decommissioning of the Susquehanna station, equal to the amount allowed for ratemaking purposes, is charged to operating expense. Such amounts are invested in trust funds which can be used only for future decommissioning costs. See Note 6.
	The U.S. Department of Energy (DOE) is responsible for the permanent storage and disposal of spent nuclear fuel removed from nuclear reactors. The Company currently pays DOE a fee for future disposal services and recovers such costs in customer rates.
Financial Investments and Marketable Securities
	In January 1994, the Company adopted SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." SFAS 115 addresses the accounting and reporting for investments in equity securities that have readily determinable fair values and for all investments in debt securities.
	Securities subject to the requirements of SFAS 115 are carried at fair value, determined at the balance sheet date. Net unrealized gains and losses on available-for-sale securities are included in common equity. Net unrealized gains and losses on trading securities are included in income. Net unrealized gains and losses on securities that are not available for unrestricted use by the Company due to regulatory or legal reasons are reflected in the related asset and liability accounts. Realized gains and losses on the sale of securities are recognized utilizing the specific cost identification method. The adoption of SFAS 115 did not have a material effect on the Company's net income. Investments in financial limited partnerships are accounted for using the equity method of accounting and venture capital investments are recorded at cost.
	For years prior to 1994, marketable equity securities were carried at the lower of their aggregate cost or market value, determined at the balance sheet date. Noncurrent marketable debt securities were carried at amortized cost. Current marketable debt securities were carried at the lower of amortized cost or market value. See Note 7.
Premium on Reacquired Long-Term Debt
	As provided in the Uniform System of Accounts, the premium paid and expenses incurred to redeem long-term debt are deferred and amortized over the life of the new debt issue or the remaining life of the retired debt when the redemption is not financed by a new issue.
Allowance for Funds Used During Construction
	As provided in the Uniform System of Accounts, the cost of funds used to finance construction projects is capitalized as part of construction cost. The components of allowance for funds used during construction (AFUDC) shown on the Consolidated Statement of Income under other income and deductions and interest charges are non-cash items equal to the cost of funds capitalized during the period.
	AFUDC serves to offset on the Consolidated Statement of Income the interest charges on debt and dividends on preferred and preference stock incurred to finance construction. In addition, a return on common equity used to finance construction is imputed.
Capital Leases
	Leased property capitalized on the Consolidated Balance Sheet is recorded at the present value of future lease payments and is amortized so that the total of interest on the lease obligation and amortization of the leased property equals the rental expense allowed for ratemaking purposes. See Note 8.
Revenues
	Electric revenues are recorded based on the amounts of electricity delivered to customers through the end of each accounting period. This includes amounts customers will be billed for electricity delivered from the time meters were last read to the end of the respective period.
	The Company's PUC tariffs contain an Energy Cost Rate (ECR) under which customers are billed an estimated amount for fuel and other energy costs. Any difference between the actual and estimated amount for such costs is collected from or refunded to customers in a subsequent period. Revenues applicable to ECR billings are recorded at the level of actual energy costs and the difference is recorded as payable to or receivable from customers.
	The Company's PUC tariffs include a Special Base Rate Credit Adjustment (SBRCA) that currently credits retail customers' bills for three nonrecurring items related to: (i) the use of an inventory method of accounting for certain power plant spare parts; (ii) the sale of capacity and related energy from the Company's wholly owned coal-fired stations to Atlantic City Electric Company (Atlantic); and (iii) the proceeds from a settlement of outstanding contract claims arising from construction of the Susquehanna station.
	The Company reflects changes in certain state taxes through a State Tax Adjustment Surcharge (STAS). See Note 3.
Income Taxes
	The Company and its wholly owned subsidiaries file a consolidated federal income tax return. Income taxes are allocated to operating expenses and other income and deductions on the Consolidated Statement of Income.
	In January 1993, the Company adopted SFAS 109, "Accounting for Income Taxes." SFAS 109 required a change from the deferred method to the asset and liability method of accounting for income taxes. See Note 5.
	The provision for deferred income taxes included on the Consolidated Statement of Income is based upon the ratemaking principles reflected in rates established by the PUC and FERC. The difference in the provision for deferred income taxes determined under SFAS 109 and the amount recorded based on ratemaking procedures adopted by the PUC and FERC is deferred and included in taxes recoverable through future rates on the Consolidated Balance Sheet. See Note 5.
	Investment tax credits were deferred when utilized and are amortized over the average lives of the related property.
Pension Plan and Other Postretirement and Postemployment Benefits
	The Company has a noncontributory pension plan covering substantially all employees, and subsidiary companies formerly engaged in coal mining have a noncontributory pension plan for substantially all non-bargaining, full-time employees. Funding is based upon actuarially determined computations that take into account the amount deductible for income tax purposes and the minimum contribution required under the Employee Retirement Income Security Act of 1974.
	In January 1993, the Company adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions." SFAS 106 requires the Company to accrue, during the years that the employees render the necessary service, the expected cost of providing retiree health care and life insurance benefits.
	In December 1993, the Company adopted SFAS 112, "Employers' Accounting for Postemployment Benefits." SFAS 112 requires the accrual of the expected cost of providing benefits to former or inactive employees after employment but before retirement.
	For additional information on these matters, see Note 11.
Cash Equivalents
	The Company considers all highly liquid debt instruments purchased with original maturities of three months or less to be cash equivalents. Reclassification
	Certain amounts from prior years' financial statements have been reclassified to conform to the current year presentation.
2. Sources of Revenues
	The Company is an operating electric utility serving about 1.2 million customers in a 10,000 square-mile territory of central eastern Pennsylvania with a population of approximately 2.6 million persons. Substantially all of the Company's operating revenues are derived from the sale of electric energy subject to PUC and FERC regulation. Customers are generally billed for electric service on a monthly basis after electricity is delivered.
	During 1994, about 98% of total operating revenues were derived from electric energy sales, with 35% coming from residential customers, 28% from commercial customers, 20% from industrial customers, 11% from contractual sales to other major utilities, 3% from energy sales to members of the Pennsylvania-New Jersey-Maryland Interconnection Association (PJM), and 3% from others. The Company's largest industrial customer provided about 1.4% of revenues from energy sales during 1994. Twenty-six industrial customers, whose billings exceeded $3 million each, provided about 7.1% of such revenues. Industrial customers are broadly distributed among industrial classifications.
3. Rate Matters
Base Rate Filing with the PUC
	In December 1994, the Company filed a request with the PUC for a $261 million increase in electric base rates, an 11.7% increase in PUC- jurisdictional rates. Various parties have filed complaints against the rate increase including the Office of Consumer Advocate (OCA), the PUC's Office of Trial Staff (OTS) and a group of industrial customers. In January 1995, the PUC suspended the request for investigation and hearings. A final rate decision is not expected until late September 1995.
	Several items included in the rate filing relate to the Company's Susquehanna station. The Company currently uses a modified sinking fund method of depreciation for property placed in service at Susquehanna prior to January 1989, which results in substantial increases in annual depreciation expense each year until 1999. At that time, annual depreciation expense is scheduled to decline by about $90 million to the amount that would have been recorded if a straight-line method of depreciation had been in effect since the in-service dates of the units. The Company is seeking to levelize this depreciation expense at an annual amount of about $173 million over the period October 1995 through December 1998, which would eliminate the currently scheduled increases in depreciation during that time period.
	The Company also is seeking recovery, over a 10-year period, of certain deferred operating and capital costs, net of energy savings, incurred from the time the Susquehanna units were placed in service until the effective dates of the rate increases for those units. These costs, which were deferred in accordance with PUC orders, total about $39 million including related deferred income taxes.
	When the PUC decided the Company's last rate case in 1985, it determined that the Company had excess generating capacity and disallowed a return on the common equity investment in Susquehanna Unit 2. The Company's generating reserves have declined over the past 10 years and are projected to be below the level considered excess by the PUC in 1985. Accordingly, the Company's rate increase request also reflects a return on its common equity investment in Susquehanna Unit 2.
	Additionally, the Company is requesting an $18 million increase in the amount it collects from customers for the estimated cost to decommission the Susquehanna station. This increase reflects a site-specific decommissioning study completed in late 1993 which indicates that the Company's 90 percent share of the cost to decommission Susquehanna will be about $724 million, an amount substantially greater than the amount currently reflected in rates.
	The Company also is requesting to collect about $43 million annually for the estimated cost of dismantling its fossil-fuel plants at the end of their expected useful lives.
	The rate request also seeks recovery of the full amount of retiree health care costs being recorded in accordance with SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," including the amount the Company began to defer as of January 1993 pursuant to a PUC order but subsequently charged to expense due to a decision by the Commonwealth Court of Pennsylvania that reversed the PUC order. The charge to expense in 1994 amounted to $22.9 million, which included $10.8 million applicable to 1993.
	The filing also requests shortening the depreciation lives of certain coal-fired generating stations by up to twelve years and lengthening the depreciation lives of certain transmission, distribution and other property.
	The Company is seeking recovery of the costs related to the voluntary early retirement program over a 5-year period, as discussed in Note 12. The rate filing reflects an estimate of the savings from the early retirement program. To the extent that the PUC permits recovery of the cost of the program in rates, the Company will record a credit to income to reverse the recoverable portion of the charge recorded in the fourth quarter of 1994.
	The Company has also proposed a method of recovering costs currently being billed to other utilities pursuant to contractual arrangements for the sale of capacity and related energy to those utilities. These contracts begin to phase-out in 1996, and the Company has proposed to recover the costs associated with the returning capacity through the ECR. Under the proposal, the ECR would be adjusted automatically each year as capacity is returned pursuant to the contracts. In this way, customer rates, through ECR billings, will reflect both the capital-related and operating costs associated with the returning capacity. The Company's proposal provides for all the revenues associated with sales of any returning capacity or related energy to be flowed through the ECR for the benefit of customers.
Energy Cost Rate Issues
	In April 1994, the PUC reduced the Company's 1994-95 ECR claim by approximately $15.7 million to reflect costs associated with replacement power during a portion of the period that Unit 1 of the Company's Susquehanna station was out of service for refueling and repairs. As a result of the PUC's action, the Company recorded a charge against income in the first quarter of 1994 for the $15.7 million of unrecovered replacement power costs. This charge adversely affected net income by about $9.0 million or 6 cents per share of common stock.
	The Company filed a complaint with the PUC objecting to the decision to exclude these replacement power costs from the 1994-95 ECR and subsequently reached a settlement with the complainants and the OTS on this matter.
	The PUC approved the settlement agreement on February 24, 1995. As a result of the PUC Order, the Company, in the first quarter of 1995, will record a credit to income of $9.7 million which would increase net income by about $5.5 million or 4 cents per share of common stock.
	In October 1994, the PUC issued an order approving the settlement agreement the Company reached in January 1994 with the OCA and certain industrial customers concerning the 1990-91 ECR through the 1993-94 ECR. The PUC order resolved all complaints against those ECRs, and required the Company to credit the 1994-95 ECR with a one-time adjustment for a portion of the receipts from installed capacity credit sales made from April 1990 through December 31, 1993 and also provided that about one-third of the receipts from installed capacity credit sales made after December 31, 1993 will be credited through future ECRs. These capacity credit sales are discussed in Notes 3 and 4. The PUC order also provided that a portion of the PUC-jurisdictional amount of deferred retired miners' health care benefits costs, which the Company sought to recover through the ECR, will not be recoverable.
	As a result of the settlement agreement, in the fourth quarter of 1993 the Company recorded a charge to expense of $17.1 million, which reduced 1993 net income by approximately $9.7 million or 6 cents per share of common stock.
Postretirement Benefits Other Than Pensions
	Pursuant to a PUC order, the Company had been deferring the increase in retiree benefits costs arising from adoption of SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" beginning January 1, 1993 until such costs were included in customer rates in the Company's next retail base rate proceeding. Accounting rules permit deferral of the costs for about five years.
	The OCA appealed the PUC's decision permitting deferral and future recovery of the increased retiree benefits costs to the Commonwealth Court of Pennsylvania. In May 1994, the Commonwealth Court reversed the PUC order and held that the Company could not defer these costs. As a result, in the second quarter of 1994, the Company began expensing the increased costs applicable to operations that would have otherwise been deferred and wrote off the costs deferred from January 1, 1993. The PUC and the Company requested the Pennsylvania Supreme Court to hear an appeal of the Commonwealth Court decision. See Note 11.
Uranium Enrichment Decontamination and Decommissioning Fund
	The Energy Policy Act of 1992 (Energy Act) provides for an assessment, over a 15-year period, on utilities with nuclear power operations, including the Company, to provide funds for the decontamination and decommissioning of DOE's uranium enrichment facilities.
	As of December 31, 1994, the Company's liability for its total assessment amounted to about $31.5 million. The liability is subject to adjustment for inflation. The corresponding charge to expense was deferred and is being amortized as the Company recovers its annual payments from customers. As a result, the assessment does not affect net income.
Special Base Rate Credit Adjustment
	The SBRCA has been in effect since April 1, 1991 and currently reduces PUC-jurisdictional customers' bills for the effects of three nonrecurring items. The first item is the annual amortization over a five-year period of a credit to income associated with the Company's use of an inventory method of accounting for power plant spare parts beginning January 1, 1991.
	The second relates to costs that are being recovered from Atlantic pursuant to the sale of 125,000 kilowatts of capacity (summer rating) and related energy from the Company's wholly owned coal-fired stations beginning October 1, 1991. The costs recovered from Atlantic are currently reflected in PUC base rate tariffs. Accordingly, the Company included a credit in the SBRCA for the costs, except energy costs, recovered from Atlantic. The change in energy costs associated with the sale is reflected in the ECR.
	The third relates to the proceeds from the settlement of outstanding contract claims arising from construction of the Susquehanna station. In accordance with approval of the settlement by the PUC, the Company began on April 1, 1992 to return the settlement proceeds to PUC customers through the SBRCA at the rate of $11 million per year for five years. In addition, the proceeds from the settlement applicable to FERC-jurisdictional and other major utilities are being credited to those customers.
	The SBRCA reduced revenues from PUC customers by about $45.4 million in 1994, $44.5 million in 1993 and $39.1 million in 1992. The reductions in revenues due to the SBRCA do not affect the Company's net income.
Refund of State Tax Decrease
	In June 1994, legislation was enacted that decreased the state corporate net income tax rate from 12.25% to 11.99% retroactive to January 1, 1994, with further reductions to 10.99%, 10.75% and 9.99% in 1995, 1996 and 1997, respectively. In accordance with the terms of its tariffs, the Company filed with the PUC a recomputation of its STAS to reflect the decrease in state income taxes for 1994. The application of the STAS reflecting the 1994 tax decrease began in July 1994 and is expected to reduce customer bills through March 1995 by about $1.5 million.
FERC-Jurisdictional Rates
	The Company has entered into five year sales contracts with certain small utilities the Company currently serves, which reduced rates to these small utilities by about $3.3 million in 1994 and will reduce rates by about an additional $4.1 million in 1996. In connection with these agreements, in the fourth quarter of 1993 the Company wrote off the deferred portions of retired miners' health care benefits costs and postretirement benefits other than pensions applicable to FERC- jurisdictional customers. The charge to expense amounted to $8.9 million, which reduced 1993 net income by $5.1 million or 3 cents per share of common stock.
4. Sales to Other Major Electric Utilities
	The Company provides Atlantic with 125,000 kilowatts of capacity (summer rating) and related energy from the Company's wholly owned coal- fired stations. Sales to Atlantic will continue through September 2000. The Company also provides Baltimore Gas & Electric (BG&E) with 129,000 kilowatts or 6.6 percent of the Company's share of capacity and related energy from the Susquehanna station. Sales to BG&E will continue through May 2001.
	The Company provides Jersey Central Power and Light Company (JCP&L) with 945,000 kilowatts of capacity and related energy from all the Company's generating units. Sales to JCP&L will continue at the 945,000 kilowatt level through 1995, with the amount then declining uniformly each year until the end of the agreement on December 31, 1999.
	These agreements provide that sales are to be made at a price equal to the Company's cost of providing service, which includes a return on the Company's investment in generating capacity. Revenues from these sales totaled $286.3 million in 1994, $282.2 million in 1993 and $293.8 million in 1992.
	The Company has also sold capacity credits to other electric utilities in the PJM from the Company's system capacity. These capacity credits are used by the other utilities to meet their installed capacity obligations in the PJM. The price received for these sales is based on a percentage of the rate the utilities would have paid to purchase installed capacity under the PJM agreement. These sales are currently being made under short-term arrangements and it is uncertain how this market will continue to develop. The Company includes, as a credit to the ECR, about one-third of the receipts from these sales.
	The Company has entered into arrangements with several utilities both inside and outside the PJM for the reservation of output from any of the Company's steam generating stations during certain periods of time. Specific deliveries of energy are requested by the purchasing utility as needed during the reservation period. One utility has agreed to purchase a maximum of 10 megawatt hours per hour of the output the Company purchases from non-utility generating companies through May 1995. The Company includes as a credit to the ECR, the revenue received for deliveries of energy under reservation of output sales, the revenue received for deliveries of output from non-utility generating companies and the foregone PJM energy savings that were not realized when PJM energy sales are reduced because of reservation agreements.
	Arrangements also have been entered into whereby PJM utilities can purchase a portion of the Company's entitlement to use the PJM transmission system to import energy from utilities outside the PJM. These transactions are made through negotiated prices for various periods of time. The Company includes, as a credit to the ECR, the foregone PJM energy savings that are not realized when the sale of transmission entitlements reduces the amount of energy the Company imports and sells to other utilities.
	Revenues from the sale of capacity credits, the reservation of output from generating units and the sale of transmission entitlements (net of the amount that is credited to customers through the ECR) totaled $28.7 million in 1994 and $35.0 million in both 1993 and 1992. For information relating to a settlement agreement between the Company and complainants to the ECR with respect to capacity-related sales, see Note 3.
5. Taxes
	In January 1993, the Company adopted SFAS 109, "Accounting for Income Taxes." SFAS 109 required a change from the deferred method to the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred income tax assets and liabilities are recognized for the tax consequences of temporary differences by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amount and the tax bases of existing assets and liabilities.
	Under SFAS 109, the Company in January 1993 recorded an increase of approximately $1.1 billion in its deferred tax liability for tax benefits previously flowed through to customers and for other temporary differences. The increased tax liability was offset by a corresponding asset representing the future revenue expected through the ratemaking process to pay for the taxes, based on the established regulatory practices and legislative history in Pennsylvania permitting recovery of actual taxes payable. The adoption of SFAS 109 did not have a material effect on the Company's net income.
	In August 1993, federal legislation was enacted that increased the corporate federal income tax rate to 35% from 34% retroactive to January 1, 1993. For 1993, the Company recorded additional income tax expense of $5.9 million and an increase in deferred income tax liabilities and taxes recoverable through future rates of $79.5 million to reflect the new tax rate.
	In June 1994, state legislation was enacted that decreased the state corporate net income tax rate from 12.25% to 11.99% retroactive to January 1, 1994, with further reductions to 10.99%, 10.75% and 9.99% in 1995, 1996 and 1997, respectively. For 1994, the Company recorded a decrease in income tax expense of $0.8 million, substantially all of which will be reflected in lower customer rates through the STAS. The Company also recorded a decrease in deferred income tax liabilities and taxes recoverable through future rates of $124.0 million to reflect the new tax rates.
	The tax effects of significant temporary differences comprising the Company's net deferred income tax liability were as follows (thousands of dollars):
December 31 1994 1993 Deferred tax assets Deferred investment tax credits $ 94,650 $ 103,084 Accrued pension costs 67,327 38,821 Other 107,830 108,441 Valuation allowance (8,183) (8,694) 261,624 241,652 Deferred tax liabilities Electric utility plant - net 1,790,378 1,892,366 Other property - net 13,829 26,629 Taxes recoverable through future rates 409,417 500,959 Reacquired debt costs 46,934 43,580 Other 20,355 35,120 2,280,913 2,498,654 Net deferred tax liability $2,019,289 $2,257,002
	In 1993, the valuation allowance related to deferred tax assets decreased $2.9 million from $11.6 million established upon the adoption of SFAS 109 at January 1, 1993.
	Details of the components of income tax expense and a reconciliation of federal income taxes derived from statutory tax rates applied to income from continuing operations for accounting purposes are as follows (thousands of dollars):
Income Tax Expense 1994 1993 1992 Included in operating expenses Provision - Federal $198,777 $162,795 $144,546 State 76,903 63,508 64,648 275,680 226,303 209,194 Deferred - Federal (34,177) 22,491 30,654 State (11,021) (124) 2,521 (45,198) 22,367 33,175 Investment tax credit, net - Federal (12,253) (13,506) (14,029) 218,229 235,164 228,340 Included in other income and deductions Provision (credit) - Federal (18,453) (5,134) 676 State (7,309) 486 483 (25,762) (4,648) 1,159 Deferred - Federal (8,688) 4,047 (441) State (4,197) (679) (396) (12,885) 3,368 (837) (38,647) (1,280) 322
Total income tax expense - Federal 125,206 170,693 161,406 State 54,376 63,191 67,256 $179,582 $233,884 $228,662
Detail of deferred taxes in operating expenses Tax depreciation $ (2,133) $ 33,195 $ 38,026 Pension and early retirement costs (28,176) (4,602) (5,341) Other (14,889) (6,226) 490 $(45,198) $ 22,367 $ 33,175
Reconciliation of Income Tax Expense Indicated federal income tax on pre-tax income at statutory tax rate (1994, 35%; 1993, 35%; 1992, 34%) $148,373 $203,704 $195,631 Increase (decrease) due to: State income taxes 35,017 41,829 44,575 Depreciation differences not normalized 14,883 8,470 6,805 Amortization of investment tax credit (12,253) (13,506) (14,029) AFUDC (Note 1) (1,640) (2,794) (2,302) Other (4,798) (3,819) (2,018) 31,209 30,180 33,031 Total income tax expense $179,582 $233,884 $228,662 Effective income tax rate 42.4% 40.2% 39.7%
Taxes, other than income, consist of the following (thousands of dollars):
Taxes, Other Than Income State gross receipts $ 99,311 $ 98,280 $ 94,926 State utility realty 46,556 45,292 48,511 State capital stock 34,739 35,943 37,279 Social security and other 20,555 24,452 24,602 $201,161 $203,967 $205,318
6. Nuclear Decommissioning Costs
	The Company's most recent estimate of the cost to decommission the Susquehanna nuclear-fueled generating station was completed in 1993 and was a site-specific study, based on immediate dismantlement and decommissioning each unit following final shutdown. The study indicates that the Company's ninety percent share of the total estimated cost of decommissioning the Susquehanna station is approximately $724 million in 1993 dollars. The operating licenses for Units 1 and 2 expire in 2022 and 2024, respectively. The estimated cost includes decommissioning the radiological portions of the station and the cost of removal of nonradiological structures and materials.
	Decommissioning costs charged to operating expense were $7.2 million in 1994, and $6.9 million in 1993 and 1992 and are based upon amounts included in customer rates. Decommissioning costs included in PUC- jurisdictional customer rates are based upon estimates developed in 1985 and are substantially lower than the level needed to recover the cost estimates in the 1993 site-specific study. In its pending base rate filing, the Company has requested an $18 million annual increase in the amount it collects from PUC-jurisdictional customers for decommissioning costs. Rates charged to other small utilities reflect the estimated cost of decommissioning in the 1993 study.
	Amounts collected from customers for decommissioning, less applicable taxes, are deposited in external trust funds for investment and can be used only for future decommissioning costs. The market value of securities held and accrued income in the trust funds at December 31, 1994 and 1993 aggregated approximately $87.5 and $82.9 million, respectively. The trust funds experienced a net loss in 1994 of $2.3 million on a fair value basis, which includes unrealized depreciation in the value of securities of $6.7 million. The net loss reduced the trust fund balance and accrued nuclear plant decommissioning costs recognized on the Company's Consolidated Balance Sheet at December 31, 1994. The net loss of the trust funds excludes the recognition by the Company of unrealized appreciation in the value of securities in the trust funds on January 1, 1994 of $5.9 million in connection with the adoption of SFAS 115, "Accounting for Certain Investments in Debt and Equity Securities." Recognition of the unrealized appreciation at January 1, 1994 increased the balance in the trust funds and accrued nuclear plant decommissioning costs recognized on the Company's Consolidated Balance Sheet.
	The Financial Accounting Standards Board is currently reviewing the accounting for removal costs, including decommissioning of nuclear power plants. As a result, current electric utility industry accounting practices for decommissioning may change, including the possibility that the estimated cost for decommissioning could be recorded as a liability on a basis other than an accrual over the estimated life of the power plant.
7. Financial Instruments
	The fair value of investments including securities subject to the requirements of SFAS 115 at December 31, 1994 on the Consolidated Balance Sheet was (thousands of dollars):
Nuclear Marketable Financial Decommissioning Aggregate Securities(a) Investments(b) Trust Fund(c)
Trading securities $ 12,302 $ 12,302 Available-for-sale securities: Equity securities 11,268 9,113 $ 2,155 Debt securities 215,189 79,122 51,502 $84,565 Total available- for-sale 226,457 88,235 53,657 84,565 Total trading and available-for-sale 238,759 100,537 53,657 84,565 Other investments 68,900 65,975 2,925 $307,659 $100,537 $119,632 $87,490
	Available-for-sale securities at amortized cost consisted of the following (thousands of dollars):
Nuclear Marketable Financial Decommissioning Aggregate Securities(a) Investments(b) Trust Fund(c)
Debt-U.S. Government $ 27,436 $ 3,414 $24,022 Debt - Municipals 187,873 75,919 $ 52,373 59,581 Debt - Other 1,656 1,656 216,965 79,333 52,373 85,259 Common Stock 9,572 9,113 459 $226,537 $88,446 $ 52,832 $85,259
	Maturities of debt securities included in available-for-sale securities consisted of the following (thousands of dollars):
Nuclear Marketable Financial Decommissioning Aggregate Securities(a) Investments(b) Trust Fund(c)
Fair Value Within 1 year $ 80,773 $79,122 $ 1,651 1-5 years 29,824 $10,353 19,471 5-10 years 46,455 11,450 35,005 over 10 years 58,137 29,699 28,438 $215,189 $79,122 $51,502 $84,565
Amortized Cost Within 1 year $ 80,989 $79,333 $ 1,656 1-5 years 29,935 $10,658 19,277 5-10 years 46,364 11,771 34,593 over 10 years 59,677 29,944 29,733 $216,965 $79,333 $52,373 $85,259
	Unrealized gains and losses on available-for-sale securities at December 31, 1994 were (thousands of dollars):
Nuclear Marketable Financial Decommissioning Aggregate Securities(a) Investments(b) Trust Fund(c)
Unrealized holding gains $3,582 $ 1 $2,363 $1,218
Unrealized holding losses $3,663 $ 212 $1,539 $1,912
	Net unrealized gains on available-for-sale securities included in common equity at December 31, 1994 amounted to $0.3 million after applicable income taxes. The net unrealized loss on trading securities included in income for 1994 was $0.2 million.
	Realized gains and losses on the sale of securities are based on the specific cost identification method. The proceeds from sales and maturities and the gross realized gains and losses for 1994 were (thousands of dollars):
Nuclear Marketable Financial Decommissioning Aggregate Securities(a) Investments(b) Trust Fund(c)
Proceeds from sales and maturities $224,453 $149,384 $28,101 $46,968 Gross realized gains $ 398 $ 48 $ 350 Gross realized losses $ 676 $ 4 $ 672
_____________________ (a)	Included in the amount shown as Current Assets-Marketable Securities on the Consolidated Balance Sheet. (b)	Included in the amount shown as Investments-Financial Investments on the Consolidated Balance Sheet. (c)	Included in the amount shown as Nuclear Plant Decommissioning Trust Funds on the Consolidated Balance Sheet. Realized and unrealized gains and losses are reflected in the related asset and liability accounts.
	The carrying amount and the estimated fair value of the Company's financial instruments are as follows (thousands of dollars):
December 31, 1994 December 31, 1993
Carrying Fair Carrying Fair Amount Value Amount Value Assets Nuclear plant decommissioning trust funds (a) $ 87,490 $ 87,490 $ 76,913 $ 82,860 Financial investments (b) 119,632 118,501 149,326 155,237 Other investments (c) 8,654 8,654 7,805 7,805 Cash and cash equivalents (c) 10,079 10,079 8,271 8,271 Marketable securities (d) 100,537 100,537 17,792 16,791 Other financial instruments included in other current assets (c) 2,435 2,435 3,102 3,102 Liabilities Preferred stock with sinking fund requirements (e) 295,000 265,275 335,000 336,388 Long-term debt (e) 2,940,789 2,756,131 2,662,570 2,843,635 Commercial paper and bank loans (c) 74,168 74,168 202,260 202,260 Taxes and interest accrued, dividends payable and other liabilities included in other current liabilities (c) 187,367 187,367 219,505 219,505 Accrued nuclear assessment -- noncurrent (c) 31,522 31,522 31,871 31,871 __________________ (a) The fair value generally is based on established market prices. For a minor portion, the fair value approximates the carrying amount. (b) The fair value is based on established market prices. For venture capital investments included in financial investments, fair value is determined in good faith by management of the venture capital entity. (c) The fair value approximates carrying amount. (d) The fair value is based on established market prices. (e) The fair value is based on quoted market prices for the securities where available and estimates based on current rates offered to the Company where quoted market prices are not available.
	Financial investments as shown on the Consolidated Balance Sheet consisted of the following (thousands of dollars):
December 31 1994 1993
Marketable equity securities $ 23,570 (a) $ 11,196 (b) Marketable debt securities 130,624 (a) 84,337 (c) Financial limited partnerships 60,739 (e) 65,378 (e) Venture capital investments 5,236 (b) 6,207 (b) 220,169 167,118 Less marketable securities included in current assets 100,537 (a) 17,792 (d) Total $119,632 $149,326 _____________
(a) At fair value (b) At cost (c) At amortized cost (d) At the lower of amortized cost or market value (e) At equity
	The fair value of marketable equity securities and marketable debt securities at December 31, 1993 was (thousands of dollars) $13,337 and $88,594, respectively.
8. Leases
	The Company has entered into capital leases consisting of the following (thousands of dollars):
December 31 1994 1993 Nuclear fuel, net of accumulated amortization (1994, $196,617; 1993, $191,812) $144,380 $173,395 Vehicles, oil storage tanks and other property, net of accumulated amortization (1994, $84,330; 1993, $83,224) 80,385 75,630 Net property under capital leases $224,765 $249,025
	Capital lease obligations incurred for the acquisition of nuclear fuel and other property were (millions of dollars): 1994, $62.0; 1993, $84.0 and 1992, $64.8.
	Nuclear fuel lease payments, which are charged to expense as the fuel is used for the generation of electricity, were (millions of dollars): 1994, $71.8; 1993, $67.6 and 1992, $70.4. Future nuclear fuel lease payments will be based on the quantity of electricity produced by the Susquehanna station. The maximum amount of unamortized nuclear fuel leasable under current arrangements is $200 million.
	Future minimum lease payments under capital leases in effect at December 31, 1994 (excluding nuclear fuel) would aggregate $96.7 million, including $16.3 million in imputed interest. During the five years ending 1999, such payments would decrease from $26.8 million per year to $7.1 million per year.
	Interest on capital lease obligations was recorded as operating expenses on the Consolidated Statement of Income in the following amounts (millions of dollars): 1994, $11.1; 1993, $9.1 and 1992, $10.5.
	Generally, capital leases contain renewal options and obligate the Company to pay maintenance, insurance and other related costs. Various operating leases have also been entered into which are not material with respect to the Company's financial position.
9. Regulatory Assets
	The Company has deferred certain costs (regulatory assets) in accordance with the rate actions of the PUC and FERC and is recovering or expects to recover such costs in electric rates charged to customers. Regulatory assets consist of the following (thousands of dollars):
December 31 1994 1993
Deferred depreciation $ 256,021 $ 282,115 Deferred operating and carrying costs - Susquehanna 39,215 39,215 Utility plant carrying charges - net of amortization 23,142 24,097 Deferred refueling outage costs - Susquehanna 14,629 16,027 Reacquired debt costs 113,466 101,836 Taxes recoverable through future rates 986,292 1,166,118 Retired miners' health care benefits 14,536 24,096 Assessment for decommissioning uranium enrichment facilities 33,492 33,710 Postretirement benefits other than pensions 14,855
$1,480,793 $1,702,069
	Deferred depreciation is the accumulated difference between the straight-line depreciation that would have been recorded on property placed in service at the Susquehanna station prior to January 1, 1989 and the amount of depreciation on such property provided for financial reporting purposes and included in rates. The annual difference is shown as amortized depreciation on the Consolidated Statement of Income.
	Deferred operating and carrying costs - Susquehanna consist of certain operating and capital costs, net of energy savings, associated with Units 1 and 2 at the Susquehanna station. The costs, deferred in accordance with orders from the PUC, were incurred from the date the units were placed in commercial operation until the effective dates of the rate increases reflecting operation of the units. The deferred costs include related deferred income taxes. See Note 3 for information on recovery of these costs. No return is being accrued on the deferred costs.
	Utility plant carrying charges were reclassified from electric utility plant in service to a deferred debit in accordance with a FERC order. Such charges are being amortized over the remaining depreciable lives of the related property and are included in PUC electric service rates.
	Deferred refueling outage costs - Susquehanna represent incremental maintenance costs incurred during refueling and inspection outages which are deferred and subsequently amortized from the cessation of the outage until the next scheduled refueling and inspection outage is completed. Such costs are included in electric service rates.
	Reacquired debt costs represent premiums and expenses incurred in the redemption of long-term debt. In accordance with FERC regulations, reacquired debt costs are amortized over either the life of the refunding issue or the remaining life of the redeemed issue, as appropriate. The Company is seeking recovery of reacquired debt costs in its current base rate filing.
	For a discussion of taxes recoverable through future rates, postretirement benefits other than pensions, retired miners' health care benefits and assessment for decommissioning uranium enrichment facilities, see Notes 3, 5 and 11.
10. Credit Arrangements
	The Company issues commercial paper and, from time to time, borrows from banks to provide short-term funds required for general corporate purposes. In addition, certain subsidiaries also borrow from banks to obtain short-term funds. Bank borrowings generally bear interest at rates negotiated at the time of the borrowing. The Company's weighted average interest rate on short-term borrowings was 6.1% and 3.4% at December 31, 1994 and 1993, respectively.
	In 1994, the Company entered into a $250 million revolving credit arrangement with a group of banks in return for the payment of commitment fees which replaced a similar credit arrangement totaling $140 million. Any loans made under this credit arrangement would mature in September 1999 and, at the option of the Company, interest rates would be based upon certificate of deposit rates, Eurodollar deposit rates or the prime rate. The Company has additional credit arrangements with another group of banks in return for the payment of commitment fees. The banks have committed to lend the Company up to $45 million under these credit arrangements, which mature on November 2, 1995 at interest rates based upon Eurodollar deposit rates or the prime rate. These credit arrangements produce a total of $295 million of lines of credit to provide back-up for the Company's commercial paper and short-term borrowings of certain subsidiaries. No borrowings were outstanding at December 31, 1994 under these credit arrangements.
	The Company leases its nuclear fuel from a trust funded by sales of commercial paper. The maximum financing capacity of the trust under existing credit arrangements is $200 million.
	Commitment fees incurred were (millions of dollars): 1994, $0.4; 1993, $0.3 and 1992, $0.4.
11. Pension Plan and Other Postretirement and Postemployment Benefits
Pension Plan
	The Company has a funded noncontributory defined benefit pension plan (Plan) covering substantially all employees. Benefits are based upon a participant's earnings and length of participation in the Plan, subject to meeting certain minimum requirements.
	The Company also has two supplemental retirement plans for certain management employees and directors that are not funded. Benefit payments pursuant to these supplemental plans are made directly by the Company. At December 31, 1994, the projected benefit obligation of these supplemental plans was approximately $12.5 million.
	The components of the Company's net periodic pension cost for the three plans were (thousands of dollars):
1994 1993 1992
Service cost-benefits earned during the period $ 33,527 $ 31,381 $ 29,967 Interest cost 51,330 48,266 44,203 Actual return on plan assets 28,680 (92,085) (95,969) Net amortization and deferral (96,413) 29,696 40,251
Net periodic pension cost $ 17,124 $ 17,258 $ 18,452
	The net periodic pension cost charged to operating expenses was $9.9 million in 1994, $10.1 million in 1993 and $11.6 million in 1992. The balance was charged to construction and other accounts. The funded status of the Company's Plan was (thousands of dollars):
December 31 1994 1993
Fair value of plan assets $888,214 $943,889 Actuarial present value of benefit obligations: Vested benefits 573,564 490,567 Nonvested benefits 1,396 1,543 Accumulated benefit obligation 574,960 492,110 Effect of projected future compensation 173,311 191,302 Projected benefit obligation 748,271 683,412
Plan assets in excess of projected benefit obligation 139,943 260,477
Unrecognized transition assets (being amortized over 23 years) (67,796) (72,316) Unrecognized prior service cost 61,941 34,240 Unrecognized net gain (288,105) (305,577)
Accrued expense $(154,017) $(83,176)
	The weighted average discount rate used in determining the actuarial present value of projected benefit obligations was 7.5% and 7.0% on December 31, 1994 and 1993, respectively. The rate of increase in future compensation used in determining the actuarial present value of projected benefit obligations was 5.7%, on December 31, 1994 and 1993. The assumed long-term rates of return on assets used in determining pension cost in 1994 and 1993 was 8.0%. Plan assets consist primarily of common stocks, government and corporate bonds and temporary cash investments.
	Subsidiary companies formerly engaged in coal mining have a noncontributory defined benefit pension plan covering substantially all non-bargaining, full-time employees which is fully funded, primarily by group annuity contracts with insurance companies. In addition, the companies are liable under federal and state laws to pay black lung benefits to claimants and dependents with respect to approved claims, and are members of a trust which was established to facilitate payment of such liabilities. Such costs were not material in 1994, 1993 and 1992.
Postretirement Benefits Other Than Pensions
	Substantially all employees of the Company and its subsidiaries will become eligible for certain health care and life insurance benefits upon retirement. The Company sponsors four health and welfare benefit plans that cover substantially all management and bargaining unit employees upon retirement. One plan provides for retiree health care benefits to certain management employees, another plan provides retiree health care benefits to bargaining unit employees, a third plan provides retiree life insurance benefits to certain management employees up to a specified amount and a fourth plan provides retiree life insurance benefits to bargaining unit employees.
	Dollar limits have been established for the amount the Company will contribute annually toward the cost of retiree health care for employees retiring after March 1993.
	In January 1993, the Company adopted SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," which requires the Company to accrue, during the years that the employees render the necessary service, the expected cost of providing retiree health care and life insurance benefits. The adoption of SFAS 106 did not have a material effect on the Company's net income. In accordance with a PUC order, the Company deferred the PUC-jurisdictional accrued cost of retiree health and life insurance benefits in excess of actual claims paid pending recovery of the increased cost in retail rates. As a result of a decision of the Commonwealth Court, in 1994, the Company began expensing the increased costs applicable to operations that were previously being deferred and wrote off such costs deferred in 1993.
	In December 1993, the Company established a separate Voluntary Employee Benefit Association trust (VEBA) for each of the four health and welfare benefit plans for retirees and adopted a funding policy that takes into account the maximum amount allowed as a deduction for federal income tax purposes. After making initial contributions, additional funding of the trusts was deferred pending resolution of the Company's ability to recover the costs of the plans in rates.
	Life insurance benefits for certain management employees beyond a specified amount are not funded through the VEBA for retiree life insurance benefits to management employees but are combined with the disclosures below for the health care and life insurance plans. The cost of retiree health care and life insurance benefits for officers of the Company are not material and are combined with the disclosures below for health care and life insurance plans.
	The following table sets forth the plans' combined funded status reconciled with the amount shown on the Company's Consolidated Balance Sheet (thousands of dollars):
December 31 1994 1993
Accumulated postretirement benefit obligation: Retirees $ 124,484 $ 95,046 Fully eligible active plan participants 13,604 32,742 Other active plan participants 68,828 75,185 206,916 202,973 Plan assets at fair value, primarily temporary cash investments 23,506 14,848 Accumulated postretirement benefit obligation in excess of plan assets 183,410 188,125 Unrecognized net loss (13,770) (20,573) Unrecognized transition obligation (being amortized over 20 years) (156,448) (165,140)
Accrued postretirement benefit cost $ 13,192 $ 2,412
	At December 31, 1993, the plan that provides retiree health care benefits to certain management employees was unfunded; the amount included in the accumulated postretirement benefit obligation attributable to that plan was (thousands of dollars) $70,630.
	The net periodic postretirement benefit cost included the following components (thousands of dollars):
1994 1993
Service cost - benefits attributed to service during the period $ 4,286 $ 3,699 Interest cost on accumulated postretirement benefit obligation 14,189 13,008 Actual return on plan assets (435) Net amortization and deferral 7,645 8,691
Net periodic postretirement benefit cost $ 25,685 $ 25,398
	Retiree health and benefits costs charged to operating expenses were approximately (millions of dollars): 1994, $27.2 (which includes $10.8 million of retiree health and benefits costs previously deferred in 1993) and 1993, $6.9. Costs in excess of the amount charged to expense were charged to construction and other accounts. In 1993, the increase in expenses due to the adoption of SFAS 106 was $2.3 million. The cost of retiree health and life insurance benefits recognized as expense by the Company and its subsidiaries in 1992 was approximately $5.5 million.
	For measurement purposes, a 9% annual rate of increase in the per capita cost of covered health care benefits was assumed for 1995; the rate was assumed to decrease gradually to 6% by 2006 and remain at that level thereafter. Increasing the assumed health care cost trend rates by 1% in each year would increase the accumulated postretirement benefit obligation as of December 31, 1994 by about $9.4 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by about $1.0 million.
	In determining the accumulated postretirement benefit obligation, the weighted average discount rate used was 7.5% and 7.0% on December 31, 1994 and 1993, respectively. The trusts holding plan assets, except for retiree health care benefits to certain management employees, are tax-exempt. The expected long-term rate of return on plan assets for the tax-exempt trusts was 6.5% on December 31, 1994 and 1993.
	Subsidiary companies formerly engaged in coal mining had accrued $32 million for an estimated payment they expected to make for future retiree health care. However, the Energy Act imposed a new liability, currently estimated at about $58 million on a net present value basis, on the Company or its subsidiary coal-mining companies for the cost of health care of retired miners previously employed by those subsidiaries.
Postemployment Benefits
	The Company provides health and life insurance benefits to disabled employees and income benefits to eligible spouses of deceased employees. In December 1993, the Company adopted SFAS 112, "Employers' Accounting for Postemployment Benefits," which requires the Company to accrue, during the years that the employees render the necessary service, the expected cost of providing benefits to former or inactive employees after employment but before retirement. The adoption of SFAS 112 did not have a material effect on the Company's net income. Postemployment benefits charged to operating expenses were $2.1 million, $6.5 million and $1.0 million for 1994, 1993 and 1992, respectively.
Employee Stock Ownership Plan
	The Company has an Employee Stock Ownership Plan (ESOP) for all full- time employees having more than one year of service. Contributions to the ESOP had been funded with investment and payroll-based tax credits previously available to the Company under federal law to acquire shares of the Company's common stock. Contributions funded with these tax credits were completed in 1991. Since 1990, all dividends on shares credited to participants' accounts have been paid in cash. The Company deducts the amount of those dividends for income tax purposes and contributes to the ESOP shares having a cost equal to the tax savings resulting from that deduction and contribution.
12. Voluntary Early Retirement Program
	As part of its efforts to continue to reduce costs, the Company offered a voluntary early retirement program to 851 employees who were age 55 or older by December 31, 1994. A total of 640 employees elected to retire under the program, at a total cost of $75.9 million. The early retirement program provided for a lump sum payment based on an employee's years of service, no reduction in retirement benefits for age and supplemental monthly payments. The Company recorded the cost of the program as a charge against income in the fourth quarter of 1994, which reduced net income by $43.4 million, or 28 cents per share of common stock. Annual savings in operating expenses associated with this program are estimated to be approximately $35 million.
	The Company's PUC base rate filing reflects an estimate of the savings from the early retirement program and seeks recovery of the cost of the program over a five-year period. To the extent that the PUC permits recovery of the cost of the program in rates, the Company will record a credit to income to recognize the income effect related to the recoverable portion of the charge recorded in 1994.
13. Jointly Owned Facilities
	At December 31, 1994, the Company or a subsidiary owned undivided interests in the following facilities (millions of dollars):
Merrill ------Generating Stations----- Creek Susquehanna Keystone Conemaugh Reservoir
Ownership interest 90.00% 12.34% 11.39% 8.37% Electric utility plant in service $4,015 $60 $91 Other property $22 Accumulated depreciation 697 29 26 6 Construction work in progress 56 2 7
	Each participant in these facilities provides its own financing. The Company receives a portion of the total output of the generating stations equal to its percentage ownership. The Company's share of fuel and other operating costs associated with the stations is reflected on the Consolidated Statement of Income. The Merrill Creek Reservoir provides water during periods of low river flow to replace water from the Delaware River used by the Company and other utilities in the production of electricity.
14. Write Down of Coal Reserves
	In connection with a review by the Company of its non-core business assets performed in 1994, a subsidiary of the Company initiated an evaluation of the carrying value of its $83.5 million investment in undeveloped coal reserves in western Pennsylvania. The Company had acquired these reserves in 1974 through the subsidiary in order to supply future coal-fired generating stations. The Company has concluded that it would not develop such reserves as a source of fuel for its generating stations.
	This evaluation of the carrying value of the subsidiary's investment in such reserves was completed by outside appraisal firms and indicated that an impairment had occurred. Accordingly, the carrying value of this investment was written down to its estimated net realizable value of $9.8 million, resulting in a $73.7 million pre-tax charge to income. This write down resulted in an after-tax charge to income of $40 million in the fourth quarter of 1994, which reduced 1994 earnings by approximately 26 cents per share of common stock.
15. Commitments and Contingent Liabilities
Construction Expenditures
	The Company's construction expenditures are estimated to aggregate $387 million in 1995, $401 million in 1996 and $478 million in 1997, including AFUDC. For discussion pertaining to construction expenditures, see Review of the Company's Financial Condition and Results of Operations under the caption "Financial Condition - Capital Expenditure Requirements" (Capital Expenditure Requirements) on page 34.
Nuclear Operations
	The Company is a member of certain insurance programs which provide coverage for property damage to members' nuclear generating stations. Facilities at the Susquehanna station are insured against property damage losses up to $3.6 billion under these programs. The Company is also a member of an insurance program which provides insurance coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions. Under the property and replacement power insurance programs, the Company could be assessed retrospective premiums in the event of the insurers' adverse loss experience. The maximum amount the Company could be assessed under these programs at December 31, 1994 was about $41.9 million.
	Nuclear Regulatory Commission regulations require that in the event of an accident, where the estimated cost of stabilization and decontamination exceeds $100 million, proceeds of property damage insurance be segregated and used, first, to place and maintain the reactor in a safe and stable condition and, second, to complete required decontamination operations before any insurance proceeds would be made available to the Company or the trustee under the Mortgage. The Company's on-site property damage insurance policies for the Susquehanna station conform to these regulations.
	The Company's public liability for claims resulting from a nuclear incident at the Susquehanna station is limited to about $8.9 billion under provisions of The Price Anderson Amendments Act of 1988 (the Act). The Company is protected against this liability by a combination of commercial insurance and an industry assessment program. A utility's liability under the assessment program will be indexed not less than once during each five- year period for inflation and will be subject to an additional surcharge of 5% in the event the total amount of public claims and costs exceeds the basic assessment. In the event of a nuclear incident at any of the reactors covered by the Act, the Company could be assessed up to $151 million per incident, payable at a rate of $20 million per year, plus the additional 5% surcharge, if applicable.
Fuel Oil Dealers' Litigation
	In August 1991, a group of 21 fuel oil dealers in the Company's service area filed a complaint against the Company in United States District Court for the Eastern District of Pennsylvania (District Court) alleging that the Company's promotion of electric heat pumps and off-peak thermal storage systems, through the use of a special customer rate (Rate RTS) and incentives to builders and developers, had violated and continues to violate the federal antitrust laws. The complaint also alleged that the Company's use of incentives for the installation of high efficiency heat pumps violated and continues to violate the Racketeer Influenced and Corrupt Organizations Act (RICO).
	The complaint requested judgment against the Company for a sum in excess of $10 million for the alleged antitrust violations, treble the damages alleged to have been sustained by the plaintiffs. Separately, the complaint requested judgment for a sum in excess of $10 million for the alleged RICO violations, treble the damages alleged to have been sustained by the plaintiffs. Finally, the complaint requested a permanent injunction against all activities found to be illegal (including the cash grant program described below).
	In April 1992, a fuel oil dealer in the Company's service area filed a class action complaint against the Company in the District Court alleging, as did the August 1991 complaint, that the Company's promotion of electric heat pumps and off-peak thermal storage systems had violated and continues to violate the federal antitrust laws. The complaint did not allege any violation of RICO, but did allege that the Company engaged in a civil conspiracy and unfair competition in violation of Pennsylvania law.
	The plaintiff sought to represent as a class all fuel oil dealers in the Company's service area. The complaint requested a permanent injunction against all activities found to be illegal and treble the damages alleged to have been sustained by the class. No specific damage amount was set forth in the complaint. This second antitrust complaint was consolidated with the August 1991 complaint for pre-trial purposes.
	In September 1992, the Court granted the Company's motion for summary judgment and dismissed both suits filed against the Company. The plaintiffs appealed the decision to the United States Court of Appeals for the Third Circuit (Court of Appeals).
	In April 1994, the Court of Appeals affirmed in part and reversed in part the District Court's decision. The Court of Appeals affirmed the District Court's grant of summary judgment for the Company as to the Company's use of Rate RTS and the Company's builder and developer incentives, but reversed and remanded as to plaintiffs' claims regarding the Company's alleged agreements with developers that their developments consist of only electrically heated units (all-electric agreements). The Court of Appeals also reversed and remanded the grant of summary judgment as to the state law claims related to such agreements.
	The case is now proceeding in the District Court on the issue of the all-electric agreements and the related state law claims. In addition, in June 1994 plaintiffs filed an amended complaint in District Court alleging that the Company's former residential conversion program -- under which cash grants were offered to contractors and homeowners to convert from fossil fuel heating systems to electric systems -- also violated the federal antitrust laws.
	The Company cannot predict the outcome of this litigation.
Clean Air Legislation and Other Environmental Matters
	The Federal Clean Air Act Amendments of 1990 deal, in part, with acid rain under Title IV, attainment of federal ambient ozone standards under Title I, and toxic air emissions under Title III. The acid rain provisions specify Phase I sulfur dioxide emission limits for about 55% of the Company's coal-fired generating capacity by January 1995, and more stringent Phase II sulfur dioxide emission limits for all of the Company's fossil-fueled generating units by January 2000.
	The Company's capital costs of compliance with the Phase I requirements under Title IV are included in the table of "Capital Expenditure Requirements" on page 35. The Company may also incur operating expenses not reflected therein, and may choose to limit the generation of certain units and to bank or trade emission allowances among its generating units or with other utilities, to the extent permitted by the legislation.
	To meet the Phase II acid rain sulfur dioxide emission standards, the Company may install flue gas desulfurization equipment (FGD) on up to 60% of its coal-fired generating capacity, purchase lower sulfur coal, and bank or trade emission allowances among its generating units or with other utilities to the extent permitted by the legislation. The exact mix of lower sulfur fuel, emission allowance purchases, sales or trades, and the amount and timing of FGD will be based on FGD installation costs, fuel cost and availability and emission allowance prices.
	The ambient ozone attainment provisions contained in Title I of the legislation require all major stationary sources within the Northeast Ozone Transport Region (which includes all of Pennsylvania) to install reasonably available control technology (RACT) for nitrogen oxides emissions by May 1995. The Company has complied with this requirement. The associated capital costs are included in the table of "Capital Expenditure Requirements" on page 34.
	Further ozone reductions may be required as a result of modeling of nitrogen oxides and volatile organic compounds emissions in the Northeast Ozone Transport Region. A two-phase nitrogen oxides reduction from pre- Clean Air Act levels has been proposed for the area where the Company's plants are located -- a 55% reduction by May 1999 and a 75% reduction by 2003 -- unless scientific studies to be completed by 1997 indicate a different reduction. The reductions would be required during a five-month ozone season from May through September.
	In addition to acid rain and ambient ozone attainment provisions, the legislation requires the Environmental Protection Agency (EPA) to conduct a study of hazardous air emissions from power plants. EPA is also studying the health effects of fine particulates which are emitted from power plants and other sources. Adverse findings from either study could cause the EPA to mandate additional ultra high efficiency particulate removal baghouses or specialized flue gas scrubbing to remove certain vaporous trace metals and certain gaseous emissions.
	In addition to the "Capital Expenditure Requirements" shown on page 35, the Company currently estimates that additional capital expenditures and operating costs for environmental compliance will be incurred beyond 1997. Capital expenditures that may be required and the additional revenue required to recover these costs, based on 1994 revenues, are as follows: Capital Cost Revenue ($ millions) Requirement Phase II acid rain 1998-2005 $300-500 3.0% Nitrogen oxides and ambient ozone by: 1999 80 0.5% 2003 150 1.3% Hazardous air emissions by 2000 310 1.8%
	Collectively, these costs represent a potential capital exposure of up to $1.0 billion beyond 1997, as well as additional operating costs in amounts which are not now determinable but could be material.
	The Pennsylvania Air Pollution Control Act implements the Federal Clean Air Act Amendments of 1990. The state legislation essentially requires that new state air emission standards be no more stringent than federal standards. This legislation has no effect on the Company's plans for compliance with the Federal Clean Air Act Amendments of 1990.
	The PUC's policy regarding the trading and usage of, and the ratemaking treatment for, emission allowances by Pennsylvania electric utilities provides, among other things, that the PUC will not require approval of specific transactions and the cost of allowances will be recognized as energy-related power production expenses and recoverable through the ECR.
	The Pennsylvania Department of Environmental Resources (DER) regulations governing the handling and disposal of industrial (or residual) solid waste require the Company to submit detailed information on waste generation, minimization and disposal practices. They also require the Company to upgrade and repermit existing ash basins at all of its coal- fired generating stations by applying updated standards for waste disposal. Ash basins that cannot be repermitted are required to close by July 1997. Any groundwater contamination caused by the basins must also be addressed. Any new ash disposal facility must meet the rigid site and design standards set forth in the regulations. In addition, the siting of future facilities at Company facilities could be affected.
	To address the DER regulations, the Company plans to install dry fly ash handling systems at the Brunner Island, Sunbury and Holtwood stations. The Company, with siting assistance from a public advisory group, has chosen mine sites at which to use the dry fly ash from the Sunbury and Holtwood stations for reclamation. In addition, the Company is exploring opportunities to beneficially use coal ash from Brunner Island in various roadway construction projects in the vicinity of the plant that may delay or preclude the need for a new disposal facility.
	Groundwater degradation related to fuel oil leakage from underground facilities and seepage from coal refuse disposal areas and coal storage piles has been identified at several Company generating stations. Many requirements of the DER regulations address these groundwater degradation issues. The Company has reviewed its remedial action plans with the DER. Remedial work is substantially completed at one generating station, and remedial work may be required at others.
	The DER regulations to implement the toxic control provisions of the Federal Water Quality Act of 1987 and to advance Pennsylvania's toxic control program authorize the DER to use both biomonitoring and a water quality based chemical-specific approach in the National Pollutant Discharge Elimination System (NPDES) permits to control toxics. In 1993, the Company received new NPDES permits for the Montour and Holtwood stations. The Montour permit contains very stringent limits for certain toxic metals and increased monitoring requirements. More toxic reduction studies will be conducted at Montour before the permit limits become effective. Additional water treatment facilities may be needed at Montour, depending on the results of the studies.
	At Holtwood, toxics are required to be monitored at the fly ash basin until its closure in 1997. No limits have been set at this time. The Company will therefore comply with an implementation schedule for such closure and for construction of a new dry fly ash handling system at Holtwood. The closure of the Holtwood fly ash basin will require changes to the facility's existing waste water treatment system. Improvements and upgrades are being planned for the Sunbury and Brunner Island waste water treatment systems to meet the anticipated permit requirements.
	Capital expenditures through 1997, to comply with the residual waste regulations, correct groundwater degradation at fossil-fueled generating stations and address waste water control at Company facilities, are included in the "Capital Expenditure Requirements" on page 34. The Company currently estimates that about $77 million of additional capital expenditures could be required beyond 1997. Actions taken to correct groundwater degradation, to comply with the DER's regulations and to address waste water control are also expected to result in increased operating costs in amounts which are not now determinable but could be material.
	The Company has been discussing with the DER the issue of potential polychlorinated biphenyl (PCB) contamination at certain of the Company's substations and pole sites. In addition, the Company at one time owned and operated a number of coal gas manufacturing facilities, all of which were later sold. During their operation, these gas plants produced waste byproducts, some amount of which may still remain at the plant sites. Also, oil and/or other contamination may exist at some of the Company's former generating facilities. As a current or past owner/operator of these sites, the Company may be liable under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (Superfund), or other laws for the costs associated with addressing any hazardous substances at these sites.
	In early 1995 the Company expects to finalize a negotiated Consent Order with the DER to address a number of these sites where remediation may be necessary or desirable. The sites will be prioritized based upon a number of factors, including any human health or environmental risk posed by the site, the public's interest in the site, and the Company's plans for the site. Under the Consent Order, the Company will not be required by DER to spend more than $5 million per year on investigation and remediation at those sites covered by the Consent Order.
	At December 31, 1994, the Company had accrued $8.3 million, representing the amount the Company can reasonably estimate it will have to spend to remediate sites involving the removal of hazardous or toxic substances including those covered by the Consent Order mentioned above. The Company is involved in several other sites where it may be required, along with other parties, to contribute to such remediation. Some of these sites have been listed by the EPA under Superfund, and others may be candidates for listing at a future date. Future cleanup or remediation work at sites currently under review, or at sites currently unknown, may result in material additional operating costs which the Company cannot estimate at this time. In addition, certain federal and state statutes, including Superfund and the Pennsylvania Hazardous Sites Cleanup Act, empower certain governmental agencies, such as the EPA and the DER, to seek compensation from the responsible parties for the lost value of damaged natural resources. The EPA and the DER may file such compensation claims against the parties, including the Company, held responsible for cleanup of such sites. Such natural resource damage claims against the Company could result in material additional liabilities.
	Concerns have been expressed by some members of the scientific community and others regarding the potential health effects of electric and magnetic fields (EMF). These fields are emitted by all devices carrying electricity, including electric transmission and distribution lines and substation equipment. Federal, state and local officials are focusing increased attention on this issue. The Company is actively participating in the current research effort to determine whether or not EMF causes any human health problems and is taking steps to reduce EMF, where practical, in the design of new transmission and distribution facilities. The Company is unable to predict what effect the EMF issue might have on Company operations and facilities.
	In complying with statutes, regulations and actions by regulatory bodies involving environmental matters, including the areas of water and air quality, hazardous and solid waste handling and disposal and toxic substances, the Company may be required to modify, replace or cease operating certain of its facilities. The Company may also incur material capital expenditures and operating expenses in amounts which are not now determinable.
Other 	At December 31, 1994, the Company had guaranteed $11.7 million of obligations of Safe Harbor. The Company does not expect to fund the guarantee and has concluded that it is impractical to determine the fair value of the guarantee.
SHAREOWNER AND INVESTOR INFORMATION
The following information is provided as a service to shareowners and other investors. For any questions you may have or additional information you may require about PP&L or your investments in the Company, please feel free to call the toll-free number listed below, or write to:
George I. Kline, Manager Investor Services Department Pennsylvania Power & Light Co. Two North Ninth Street Allentown, PA 18101-1179
Toll-Free Phone Number: For information regarding your investor account, or other inquiries, call toll-free: 800- 345-3085.
Annual Meeting: The annual meeting of shareowners is held each year on the fourth Wednesday of April. The 1995 annual meeting will be held at 1:30 p.m. on Wednesday, April 26, 1995, at Lehigh University's Stabler Arena, Lower Saucon Valley Goodman Campus Complex, Bethlehem, PA. A reservation card for meeting attendance is included with shareowners' proxy material.
Proxy Material: A proxy statement, a proxy and a reservation card for the Company's annual meeting are mailed in a package that includes the Company's Annual Report. This material was mailed to all shareowners of record as of February 28, 1995.
Dividends: For 1995, the dates the declaration of dividends is considered by the board or its executive committee are: February 22, May 24, August 23 and November 22, for payment on April 1, July 1 and October 1, 1995, and January 1, 1996, respectively. Dividend checks are mailed ahead of those dates with the intention that they arrive as close as possible to the payment dates.
Record Dates: The 1995 record dates for dividends are March 10, June 9, September 8 and December 8.
Direct Deposit of Dividends: Shareowners may choose to have their dividend checks deposited directly into their checking or savings account. Quarterly dividend payments are electronically credited on the dividend date, or the first business day thereafter.
Dividend Reinvestment Plan: Shareowners may choose to have dividends on their common or preferred stocks reinvested in PP&L common stock instead of receiving the dividend by check.
Certificate Safekeeping: Shareowners participating in the Dividend Reinvestment Plan may choose to have their common stock certificates forwarded to the Company for safekeeping. These shares will be registered in the name of the Company as agent for plan participants and will be credited to the participants' accounts.
Lost Dividend or Interest Checks: Dividend or interest checks lost by investors, or those that may be lost in the mail, will be replaced if the check has not been located by the 10th business day following the payment date.
Transfer of Stock or Bonds: Stock or bonds may be transferred from one name to another or to a new account in the name of another person. Please call or write regarding transfer instructions.
Bondholder Information: Much of the information and many of the procedures detailed here for shareowners also apply to bondholders. Questions related to bondholder accounts should be directed to Investor Services.
Lost Stock or Bond Certificates: Please call or write to Investor Services for an explanation of the procedure to replace lost stock or bond certificates.
Publications: Several publications are prepared each year and sent to all investors of record and to others who request their names be placed on our mailing lists. These publications are:
Annual Report -- published and mailed to all shareowners of record in mid-March.
Shareowners' Newsletter -- an easy-to-read newsletter containing current items of interest to shareowners -- published and mailed at the beginning of each quarter. Additionally, a special year-end edition containing unaudited results of the year's operations is mailed in early February.
Quarterly Review -- published in May, August and November to provide quarterly financial information to investors.
Periodic Mailings: Letters from the Company regarding new investor programs, special items of interest, or other pertinent information are mailed on a non-scheduled basis as necessary.
Duplicate Mailings: Annual reports and other investor publications are mailed to each investor account. If you have more than one account, or if there is more than one investor in your household, you may call or write to request that only one publication be delivered to your address. Please provide account numbers for all duplicate mailings.
Form 10-K and PP&L Profile: The Company's annual report, filed with the Securities and Exchange Commission on Form 10-K, is available about mid-March. The PP&L Profile, a 10- year statistical review containing in-depth information about the Company, is available in May. Investors may obtain a copy of these publications, at no cost, by calling or writing to Investor Services.
Listed Securities: Fiscal Agents: New York Stock Exchange Stock Transfer Agents and Common Stock (Code: PPL) Registrars 4-1/2% Preferred Stock First Chicago Trust Co. of (Code: PPLPRB) New York 4.40% Series Preferred Stock P.O. Box 2506 (Code: PPLPRA) Suite 4659 Jersey City, NJ 07303-2506
Philadelphia Stock Exchange Pennsylvania Power & Light Co. Common Stock Investor Services Department 4-1/2% Preferred Stock Dividend Disbursing Office 3.35% Series Preferred Stock and Dividend Reinvestment 4.40% Series Preferred Stock Plan Agent 4.60% Series Preferred Stock Pennsylvania Power & Light Co. Investor Services Department Mortgage Bond Trustee Bankers Trust Co. Attn: Security Transfer Unit P.O. Box 291569 Nashville, TN 37229 Bond Interest Paying Agent Pennsylvania Power & Light Co. Investor Services Department
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information for this item concerning directors of the Company will be set forth in the sections entitled "Nominees for Directors" and "Directors Continuing in Office" in the Company's 1995 Notice of Annual Meeting and Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days after December 31, 1994, and such information is incorporated herein by reference.
Information required by this item concerning the executive officers of the Company is set forth on pages 22 through 24 of this report.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
Information for this item will be set forth in the sections entitled "Compensation of Directors," "Summary Compensation Table" and "Retirement Plans for Executive Officers" in the Company's 1995 Notice of Annual Meeting and Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days after December 31, 1994, and such information is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Information for this item will be set forth in the section entitled "Stock Ownership" in the Company's 1995 Notice of Annual Meeting and Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days after December 31, 1994, and such information is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information for this item will be set forth in the section entitled "Certain Transactions Involving Directors or Executive Officers" in the Company's 1995 Notice of Annual Meeting and Proxy Statement, which will be filed with the Securities and Exchange Commission not later than 120 days after December 31, 1994, and such information is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements - included in response to Item 8.
Independent Auditors' Report Consolidated Statement of Income for the Three Years Ended December 31, 1994 Consolidated Statement of Cash Flows for the Three Years Ended December 31, 1994 Consolidated Balance Sheet at December 31, 1994 and 1993 Consolidated Statement of Shareowners' Common Equity for the Three Years Ended December 31, 1994 Consolidated Statement of Preferred and Preference Stock at December 31, 1994 and 1993 Consolidated Statement of Long-Term Debt at December 31, 1994 and 1993 Notes to Financial Statements
2. Supplementary Data and Supplemental Financial Statement Schedule - included in response to Item 8.
Schedule II - Valuation and Qualifying Accounts and Reserves for the Three Years Ended December 31, 1994
All other schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements or notes thereto.
3. Exhibits
Exhibit Index on page 96.
(b) Reports on Form 8-K:
The following Reports on Form 8-K were filed during the three months ended December 31, 1994:
Report dated October 3, 1994
Item 5. Other Events
Information regarding (l) the Company's early retirement program offer to eligible employees, and (2) an agreement in principle to settle the Company's proposed 1994-95 ECR proceeding.
Item 7. Financial Statements, Pro Forma Financial Infor- mation and Exhibits.
Conformed copy of Sixty-second Supplemental Indenture related to the Company's issuance of First Mortgage Bonds, Pollution Control Series J, filed as an Exhibit to the Report on Form 8-K.
Conformed copy of Underwriting Agreement and Sixty-third Supplemental Indenture related to the Company's issuance of $200,000,000 principal amount of First Mortgage Bonds, 7.70% Series due 2009, filed as Exhibits to the Report on Form 8-K.
Conformed copy of Consent of Counsel.
Statement of Eligibility of Trustee, filed due to the designation of Bankers Trust Company as Trustee under the Company's Mortgage and Deed of Trust, as successor to Morgan Guaranty Trust Company of New York.
No financial statements were required to be filed with the above referenced report.
Report dated December 12, 1994
Item 5. Other Events
Information regarding the write down of a Company subsidiary's undeveloped coal reserves to net realizable value.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PENNSYLVANIA POWER & LIGHT COMPANY (Registrant)
By (Signed) William F. Hecht William F. Hecht - Chairman, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
Title
By (Signed) William F. Hecht Principal Executive William F. Hecht - Chairman, President Officer and Director and Chief Executive Officer
By (Signed) R. E. Hill Principal Financial and R. E. Hill - Senior Vice President- Accounting Officer Financial
By (Signed) J. J. McCabe Chief Accounting J. J. McCabe - Controller Officer
Richard S. Barton Jeffrey J. Burdge E. Allen Deaver Nance K. Dicciani William J. Flood Daniel G. Gambet Elmer D. Gates Directors Stuart Heydt Clifford L. Jones John T. Kauffman Robert Y. Kaufman Ruth Leventhal Francis A. Long Norman Robertson David L. Tressler
By (Signed) William F. Hecht William F. Hecht, Attorney-in-fact
PENNSYLVANIA POWER AND LIGHT COMPANY
EXHIBIT INDEX
The following Exhibits indicated by an asterisk preceding the Exhibit number are filed herewith. The balance of the Exhibits have heretofore been filed with the Commission and pursuant to Rule 12(b)-32 are incorporated herein by reference. Exhibits indicated by a # are filed or listed pursuant to Item 601(b)(10)(iii) of Regulation S-K.
3(i) - Copy of Restated Articles of Incorporation (Exhibit 3(i) to the Company's Form 8-K Report (File No. 1-905) dated January 26, 1994)
3(i)-1 - Copy of Amendments to the Restated Articles of Incorporation (Exhibit 4(b) to the Company's Form 8-K Report (File No. 1-905) dated March 15, 1994)
3(ii) - Copy of By-laws (Exhibit 3(ii) to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1993)
4(a)-1 - Copy of Amended and Restated Employee Stock Ownership Plan, dated October 26, 1988 (Exhibit 4(b) to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1988)
4(a)-2 - Copy of Amendment No. 1 to said Employee Stock Ownership Plan, effective January 1, 1989 (Exhibit 4(b)-2 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1989)
4(a)-3 - Copy of Amendment No. 2 to said Employee Stock Ownership Plan, effective January 1, 1990 (Exhibit 4(b)-3 to the Company's Form 10-K Report (File No. 1 - 905) for the year ended December 31, 1989)
4(a)-4 - Copy of Amendment No. 3 to said Employee Stock Ownership Plan, effective January 1, 1991 (Exhibit 4(b)-4 to the Company's Form 10-K Report (File No. 1 - 905) for the year ended December 31, 1990)
4(a)-5 - Copy of Amendment No. 4 to said Employee Stock Ownership Plan, effective January 1, 1991 (Exhibit 4(a)-5 to the Company's Form 10-K Report (File No. 1 - 905) for the year ended December 31, 1991)
4(a)-6 - Copy of Amendment No. 5 to said Employee Stock Ownership Plan, effective October 23, 1991 (Exhibit 4(a)-6 to the Company's Form 10-K Report (File No. 1 - 905) for the year ended December 31, 1991)
4(a)-7 - Copy of Amendment No. 6 to said Employee Stock Ownership Plan, effective January 1, 1990 and January 1, 1992 (Exhibit 4(a)-7 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
4(a)-8 - Copy of Amendment No. 7 to said Employee Stock Ownership Plan, effective January 1, 1992 (Exhibit 4(a)-8 to the Company's Form 10-K Report (File No. 1 - 905) for the year ended December 31, 1991)
4(a)-9 - Copy of Amendment No. 8 to said Employee Stock Ownership Plan, effective July 1, 1992 (Exhibit 4(a)-9 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1992)
4(a)-10 - Copy of Amendment No. 9 to said Employee Stock Ownership Plan, effective January 1, 1993 (Exhibit 4(a)-10 to the Company's Form 10-K Report (File No. 1 - 905) for the year ended December 31, 1992)
4(a)-11 - Copy of Amendment No. 10 to said Employee Stock Ownership Plan, effective January 1, 1993 (Exhibit 4(a)-11 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1993)
*4(a)-12 - Copy of Amendment No. 11 to said Employee Stock Ownership Plan, effective January 1, 1994
*4(a)-13 - Copy of Amendment No. 12 to said Employee Stock Ownership Plan, effective January 1, 1994
*4(a)-14 - Copy of Amendment No. 14 to said Employee Stock Ownership Plan, effective January 1, 1989 and January 1, 1995
4(b)-l - Mortgage and Deed of Trust, dated as of October l, 1945, between the Company and Guaranty Trust Company of New York (now Morgan Guaranty Trust Company of New York), as Trustee (Exhibit 2(a)-4 to Registration Statement No. 2-60291)
4(b)-2 - Supplement, dated as of July 1, 1954, to said Mortgage and Deed of Trust (Exhibit 2(b)-5 to Registration Statement No. 219255)
4(b)-3 - Supplement, dated as of June l, 1966, to said Mortgage and Deed of Trust (Exhibit 2(a)-l3 to Registration Statement No. 2-60291)
4(b)-4 - Supplement, dated as of November 1, 1967, to said Mortgage and Deed of Trust (Exhibit 2(a)-14 to Registration Statement No. 2-60291)
4(b)-5 - Supplement, dated as of January 1, 1969, to said Mortgage and Deed of Trust (Exhibit 2(a)-16 to Registration Statement No. 2-60291)
4(b)-6 - Supplement, dated as of June 1, 1969, to said Mortgage and Deed of Trust (Exhibit 2(a)-17 to Registration Statement No. 2-60291)
4(b)-7 - Supplement, dated as of February 1, 1971, to said Mortgage and Deed of Trust (Exhibit 2(a)-19 to Registration Statement No. 2-60291)
4(b)-8 - Supplement, dated as of February 1, 1972, to said Mortgage and Deed of Trust (Exhibit 2(a)-20 to Registration Statement No. 2-60291)
4(b)-9 - Supplement, dated as of January 1, 1973, to said Mortgage and Deed of Trust (Exhibit 2(a)-21 to Registration Statement No. 2-60291)
4(b)-10 - Supplement, dated as of June 15, 1985, to said Mortgage and Deed of Trust (Exhibit 4(a)-35 to the Company's Form l0-K Report (File No. l-905) for the year ended December 31, 1985)
4(b)-11 - Supplement, dated as of October 1, 1989, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K Report (File No. 1-905) dated November 6, 1989)
4(b)-12 - Supplement, dated as of July 1, 1991, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8- K Report (File No. 1-905) dated July 29, 1991)
4(b)-13 - Supplement, dated as of May 1, 1992, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K Report (File No. 1-905) dated June 1, 1992)
4(b)-14 - Supplement, dated as of November 1, 1992, to said Mortgage and Deed of Trust (Exhibit 4(b)-29 to the Company's Form 10-K Report (File 1-905) for the year ended December 31, 1992)
4(b)-15 - Supplement, dated as of February 1, 1993, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K Report (File No. 1-905) dated February 16, 1993)
4(b)-16 - Supplement, dated as of April 1, 1993, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K Report (File No. 1-905) dated April 30,
4(b)-17 - Supplement, dated as of June 1, 1993, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K Report (File No. 1-905) dated July 7, 1993)
4(b)-18 - Supplement, dated as of October 1, 1993, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K Report (File No. 1-905) dated October 29, 1993)
4(b)-19 - Supplement, dated as of February 15, 1994, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K Report (File No. 1-905) dated March 11, 1994)
4(b)-20 - Supplement, dated as of March 1, 1994, to said Mortgage and Deed of Trust (Exhibit 4(b) to the Company's Form 8-K Report (File No. 1-905) dated March 11, 1994)
4(b)-21 - Supplement, dated as of March 15, 1994, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K Report (File No. 1-905) dated March 30, 1994)
4(b)-22 - Supplement, dated as of September 1, 1994, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K (File No. 1-905) dated October 3, 1994)
4(b)-23 - Supplement, dated as of October 1, 1994, to said Mortgage and Deed of Trust (Exhibit 4(a) to the Company's Form 8-K Report (File No. 1-905) dated October 3, 1994)
*l0(a)-1 - Revolving Credit Agreement, dated as of August 30, 1994, between the Company and the Banks named therein
l0(b) - Copy of Pollution Control Facilities Agreement, dated as of May 1, 1973, between the Company and the Lehigh County Industrial Development Authority (Exhibit 5(z) to Registration Statement No. 2-60834)
l0(c)-l - Copy of Interconnection Agreement, dated September 26, 1956, among Public Service Electric & Gas Company, Philadelphia Electric Company, the Company, Baltimore Gas & Electric Company, Pennsylvania Electric Company, Metropolitan Edison Company, New Jersey Power & Light Company and Jersey Central Power & Light Company (Exhibit 5(e) to Registration Statement No. 2-60291)
l0(c)-2 - Copy of Supplemental Agreement, dated April 1, 1974, to said Interconnection Agreement (Exhibit 5(f)-4 to Registration Statement No. 2-51312)
l0(c)-3 - Copy of Supplemental Agreement, dated June 15, 1977, to said Interconnection Agreement (Exhibit 5(e)-5 to Registration Statement No. 2-60291)
l0(c)-4 - Copy of Agreement of Settlement and Compromise, dated July 25, 1980, among the parties to said Interconnection Agreement (Exhibit 20(b)-8 to the Company's Form l0-Q Report (File No. l-905) for the quarter ended September 30, 1980)
l0(c)-5 - Copy of Supplemental Agreement, dated March 26, 1981, to said Interconnection Agreement (Exhibit l0(b)-l0 to the Company's Form l0-K Report (File No. 1-905) for the year ended December 31, 1981)
l0(c)-6 - Copy of Revisions to Schedules 4.02, 7.01, and 9.01, all effective August 9, 1982, to said Interconnection Agreement (Exhibit 10(e)-11 to the Company's Form l0- K Report (File No. l-905) for the year ended December 31, 1982)
l0(c)-7 - Copy of Schedules 4.02, 5.01, 5.02, 5.04, 5.05, 6.01, 6.03, 6.04, 7.01, 7.02 7.03; all effective February 6, 1984, to said Interconnection Agreement (Exhibit 10(e)-8 to the Company's Form l0-K Report (File No. 1-905) for the year ended December 31, 1985)
l0(c)-8 - Copy of Schedule 5.03, Revision l, Exhibit A, revised May 31, 1985, to said Interconnection Agreement (Exhibit 10(e)-10 to the Company's Form l0-K Report (File No. 1-905) for the year ended December 31, 1985)
10(c)-9 - Copy of Schedule 4.02, Revision No. 2, effective December 4, 1989, to said Interconnection Agreement (Exhibit 10(d)-13 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1989)
10(c)-10 - Copy of Schedule 5.06, Revision No. 1, effective June 1, 1990, to said Interconnection Agreement (Exhibit 10(d)-14 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1990)
10(c)-11 - Copy of Schedule 2.21, Revision No. 1, effective June 1, 1990, to said Interconnection Agreement (Exhibit 10(d)-15 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1990)
10(c)-12 - Copy of Schedule 2.212, Revision No. 2, effective June 1, 1990, to said Interconnection Agreement (Exhibit 10(d)-16 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1990)
10(c)-13 - Copy of Schedule 9.01, Revision No. 4, effective June 1, 1992, to said Interconnection Agreement (Exhibit 10(d)-18 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1990)
10(c)-14 - Copy of Schedule 3.01, Revision No. 3, effective June 1, 1992, to said Interconnection Agreement (Exhibit 10(c)-15 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
10(c)-15 - Copy of Schedule 4.01, Revision No. 13, effective June 1, 1993, to said Interconnection Agreement (Exhibit 10(c)-15 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1993)
l0(d) - Copy of Capacity and Energy Sales Agreement, dated June 29, 1983, between the Company and Atlantic City Electric Company (Exhibit 10(f)-2 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1983)
10(e)-1 - Copy of Capacity and Energy Sales Agreement, dated March 9, 1984, between the Company and Jersey Central Power & Light Company (Exhibit l0(f)-3 to the Company's Form l0-K Report (File No. 1- 905) for the year ended December 31, 1984)
10(e)-2 - Copy of First Supplement, effective February 28, 1986, to said Capacity and Energy Sales Agreement (Exhibit 10(e)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1986)
10(e)-3 - Copy of Second Supplement, effective January 1, 1987, to said Capacity and Energy Sales Agreement (Exhibit 10(g)-3 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1989)
10(e)-4 - Copy of amendments to Exhibit A, effective October 1, 1987, to said Capacity and Energy Sales Agreement (Exhibit 10(e)-6 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1987)
10(e)-5 - Copy of Third Supplement, effective December 1, 1988, to said Capacity and Energy Sales Agreement (Exhibit 10(g)-5 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1989)
10(e)-6 - Copy of Fourth Supplement, effective December 1, 1988, to said Capacity and Energy Sales Agreement (Exhibit 10(g)-6 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1989)
10(f)-1 - Copy of Capacity and Energy Sales Agreement, dated December 21, 1989, between the Company and GPU Service Corporation (Exhibit 10(h) to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1989)
10(f)-2 - Copy of First Supplement, effective June 1, 1991, to said Capacity and Energy Sales Agreement between the Company and GPU Service Corporation (Exhibit 10(f)-2 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
10(g)-1 - Copy of Capacity and Energy Sales Agreement, dated January 28, 1988, between the Company and Baltimore Gas and Electric Company (Exhibit 10(e)-7 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1987)
10(g)-2 - Copy of First Supplement, effective November 1, 1988, to said Capacity and Energy Sales Agreement (Exhibit 10(i)-2 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1989)
10(g)-3 - Copy of Second Supplement, effective June 1, 1989, to said Capacity and Energy Sales Agreement (Exhibit 10(i)-3 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1989)
10(g)-4 - Copy of Third Supplement, effective June 1, 1991, to said Capacity and Energy Sales Agreement between the Company and Baltimore Gas & Electric Company (Exhibit 10(g)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(h)-1 - Copy of Amended and Restated Directors Deferred Compensation Plan, effective January 1, 1990 (Exhibit 10(q) to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1990)
#10(h)-2 - Copy of Amendment No. 1 to said Directors Deferred Compensation Plan, effective January 1, 1991 (Exhibit 10(h)-2 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(h)-3 - Copy of Amendment No. 2 to said Directors Deferred Compensation Plan, effective October 23, 1991 (Exhibit 10(h)-3 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(h)-4 - Copy of Amendment No. 3 to said Directors Deferred Compensation Plan, effective January 1, 1992 and April 1, 1992 (Exhibit 10(h)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(i)-1 - Copy of Directors Retirement Plan, effective January 1, 1988 (Exhibit 10(f)-2 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1988)
#10(i)-2 - Copy of Amendment No. 1 to said Directors Retirement Plan, effective January 1, 1991 (Exhibit 10(i)-2 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(i)-3 - Copy of Amendment No. 2 to said Directors Retirement Plan, effective October 23, 1991 (Exhibit 10(i)-3 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(i)-4 - Copy of Amendment No. 3 to said Directors Retirement Plan, effective January 1, 1992 (Exhibit 10(i)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(j)-1 - Copy of Amended and Restated Deferred Compensation Plan for Executive Officers, effective January 1, 1990 (Exhibit 10(s) to the Company's Form 10-K Report (File No. 1- 905) for the year ended December 31, 1990)
#10(j)-2 - Copy of Amendment No. 1 to said Officers Deferred Compensation Plan, effective January 1, 1991 (Exhibit 10(j)-2 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(j)-3 - Copy of Amendment No. 2 to said Officers Deferred Compensation Plan, effective October 23, 1991 (Exhibit 10(j)-3 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(j)-4 - Copy of Amendment No. 3 to said Officers Deferred Compensation Plan, effective January 1, 1992 and April 1, 1992 (Exhibit 10(j)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
*#10(j)-5 - Copy of Amendment No. 4 to said Officers Deferred Compensation Plan, effective January 1, 1995
#l0(k)-1 - Copy of Supplemental Executive Retirement Plan, effective January 1, 1987 (Exhibit 10(f)-3 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1986)
#10(k)-2 - Copy of Amendment No. 1 to said Supplemental Executive Retirement Plan, effective January 1, 1987 (Exhibit 10(f)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1987)
#10(k)-3 - Copy of Amendment No. 2 to said Supplemental Executive Retirement Plan, effective January 1, 1990 (Exhibit 10(t)-3 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1990)
#10(k)-4 - Copy of Amendment No. 3 to said Supplemental Executive Retirement Plan, effective November 1, 1990 (Exhibit 10(t)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1990)
#10(k)-5 - Copy of Amendment No. 4 to said Supplemental Executive Retirement Plan, effective January 1, 1991 (Exhibit 10(k)-5 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(k)-6 - Copy of Amendment No. 5 to said Supplemental Executive Retirement Plan, effective October 23, 1991 (Exhibit 10(k)-6 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(k)-7 - Copy of Amendment No. 6 to said Supplemental Executive Retirement Plan, effective January 1, 1992 (Exhibit 10(k)-7 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(k)-8 - Copy of Amendment No. 7 to said Supplemental Executive Retirement Plan, effective July 1, 1992 (Exhibit 10(k)-8 to the Company's Form 10-K Report (File No. 1- 905) for the year ended December 31, 1992)
#10(k)-9 - Copy of Amendment No. 8 to said Supplemental Executive Retirement Plan, effective January 1, 1993 (Exhibit 10(k)-9 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1993)
*#10(k)-10- Copy of Amendment No. 9 to said Supplemental Executive Retirement Plan, effective July 1, 1994
*#10(k)-11- Copy of Amendment No. 10 to said Supplemental Executive Retirement Plan, effective January 1, 1995
#10(l)-1- Copy of Executive Retirement Security Plan, effective January 1, 1987 (Exhibit 10(f)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1986)
#10(l)-2 - Copy of Amendment No. 1 to said Executive Retirement Security Plan, effective January 1, 1987 (Exhibit 10(f)-6 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1987)
#10(l)-3 - Copy of Amendment No. 2 to said Executive Retirement Security Plan, effective January 1, 1990 (Exhibit 10(u)-3 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1990)
#10(l)-4 - Copy of Amendment No. 3 to said Executive Retirement Security Plan, effective November 1, 1990 (Exhibit 10(u)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1990)
#10(l)-5 - Copy of Amendment No. 4 to said Executive Retirement Security Plan, effective January 1, 1991 (Exhibit 10(l)-5 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(l)-6 - Copy of Amendment No. 5 to said Executive Retirement Security Plan, effective October 23, 1991 (Exhibit 10(l)-6 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(l)-7 - Copy of Amendment No. 6 to said Executive Retirement Security Plan, effective January 1, 1992 (Exhibit 10(l)-7 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1991)
#10(l)-8 - Copy of Amendment No. 7 to said Executive Retirement Security Plan, effective January 1, 1993 (Exhibit 10(l)-8 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1994)
*#10(l)-9 - Copy of Amendment No. 8 to said Executive Retirement Security Plan, effective July 1,
*#10(l)-10 - Copy of Amendment No. 9 to said Executive Retirement Security Plan, effective January 1, 1995 and upon the effectiveness of the Agreement and Plan of Exchange between the Company and PP&L Resources, Inc.
*#10(l)-11 - Copy of Amendment No. 10 to said Executive Retirement Security Plan, effective January 1, 1995
#10(m)-1 - Copy of Amended and Restated Incentive Compensation Plan, effective July 1, 1992 (Exhibit 10(m)-4 to the Company's Form 10-K Report (File No. 1-905) for the year ended December 31, 1992)
*#10(n) - Description of Executive Compensation Incentive Award Program, effective January 1, 1995 (Footnote 1/)
10(o) - Conformed copy of Nuclear Fuel Lease, dated as of February 1, 1982, between the Com pany, as lessee, and Newton I. Waldman, not in his individual capacity, but solely as Cotrustee of the Pennsylvania Power & Light Energy Trust, as lessor (Exhibit 10(g) to the Company's Form l0-K Report (File No. 1- 905) for the year ended December 31, 1981)
*12 - Computation of Ratio of Earnings to Fixed Charges *16 - Letter re: Change in Certifying Accountants (Exhibit 16 to the Company's Form 8-K Report (File No. 1-905) dated February 1, 1995)
*23 - Consent of Deloitte & Touche
*24 - Power of Attorney
*27 - Financial Data Schedule
*99 - Schedule of Property, Plant and Equipment
________________________
Certain long-term debt instruments of the Company's consolidated subsidiaries have been omitted from this filing pursuant to 17 C.F.R. Section 229.601(b)(4)(iii)(A). The Company will furnish a copy of any such instrument to the Commission upon request.
_______________________________ Footnote 1/ This description is provided pursuant to 17 C.F.R. Section 229.601(b)(10)(iii)(A).
(PP&L LOGO Appears Here) Pennsylvania Power & Light Company Two North Ninth Street - Allentown, PA 18101