ITEM 1. BUSINESS
The Company
PECO Energy Company (Company), formerly known as Philadelphia Electric Company, incorporated in Pennsylvania in 1929, is an operating utility which provides electric and gas service to the public in southeastern Pennsylvania. Two subsidiaries own, and a third subsidiary operates, the Conowingo Hydro-Electric Project (Conowingo Project), and one distribution subsidiary provides electric service to the public in certain areas of northeastern Maryland adjacent to the Conowingo Project.
The total area served by the Company and its subsidiaries covers 2,475 square miles. Electric service is supplied in an area of 2,340 square miles with a population of about 3,700,000, including 1,600,000 in the City of Philadelphia. Approximately 95% of the electric service area and 64% of retail kilowatthour (kWh) sales are in the suburbs around Philadelphia and in northeastern Maryland, and 5% of the service area and 36% of such sales are in the City of Philadelphia. In 1993, approximately 60% of the Company's electric output was generated from nuclear sources. The Company estimates for 1994 that 59% of its electric output will be generated from nuclear sources (see "Fuel"). Natural gas service is supplied in a 1,475-square-mile area of southeastern Pennsylvania adjacent to Philadelphia with a population of 1,900,000. The Company and its subsidiaries hold franchises to the extent necessary to operate in the areas served.
The Company is subject to regulation by the Pennsylvania Public Utility Commission (PUC) as to rates, issuances of securities and certain other aspects of the Company's operations and by the Federal Energy Regulatory Commission (FERC) as to wholesale and interstate electric rates and as to licensing jurisdiction over the Company's Muddy Run Pumped Storage Project. Specific operations of the Company are also subject to the jurisdiction of various other federal, state, regional and local agencies, including the United States Nuclear Regulatory Commission (NRC), the United States Environmental Protection Agency (EPA), the United States Department of Energy (DOE), the Delaware River Basin Commission and the Pennsylvania Department of Environmental Resources (PDER). The Company's utility subsidiaries are subject to similar regulation, including the licensing jurisdiction of the FERC over the Conowingo Project. Due to its ownership of subsidiary-company stock, the Company is a holding company as defined by the Public Utility Holding Company Act of 1935 (1935 Act); however, it is predominantly an operating company and, by filing an exemption statement annually, is exempt from all provisions of the 1935 Act, except Section 9(a)(2) relating to the acquisition of securities of a public utility company.
Electric Operations
General
During 1993, 90.4% of the Company's operating revenues and 94.3% of its operating income were from electric operations. Electric sales and operating revenues for 1993 by classes of customers are set forth below:
In 1993, 97.7% of the Company's service territory operating revenues were from Company sales in Pennsylvania and 2.3% were from sales by the Company's wholly owned subsidiary Conowingo Power Company (COPCO) in Maryland. On February 15, 1994, the Company announced that it is evaluating strategic alternatives with respect to COPCO, including the possible sale of COPCO to other companies. The Company has made no determination at this time to sell COPCO and may, in fact, retain ownership of COPCO. See "Rate Matters."
For 1993, sales to other utilities consisted of negotiated agreements to sell 799 megawatts (MW) of near-term excess capacity and/or associated energy. See "Rate Matters." All of these agreements are either for ongoing, short-duration purchases of energy only or expire during 1994. The Company expects to renew these agreements or negotiate new agreements in 1994.
The net installed electric generating capacity (summer rating) of the Company and its subsidiaries at December 31, 1993 was as follows:
---------- (1) Includes capacity sold to other utilities. (2) See "Fuel" for sources of fuels used in electric generation.
The maximum hourly demand on the Company's system was 7,100 MW which occurred on July 8, 1993. The Company estimates its generating reserve margin for 1994 to be 28%. This is based on the most recent annual peak-load forecast, which assumes normal peak weather conditions and the sale to other utilities of 400 MW of capacity not included in rate base.
The Company is a member of the Pennsylvania-New Jersey-Maryland Interconnection (PJM), which fully integrates, on the basis of relative cost of generation, the bulk-power generating and transmission operations of eleven investor-owned electric utilities serving more than 22 million people in a 50,000-square-mile territory. In addition, PJM companies coordinate planning and install facilities to obtain the greatest practicable degree of reliability, compatible economy, and other advantages from the pooling of their respective electric system loads, transmission facilities and generating capacity. PJM uses the split-savings method in pricing and accounting to provide an economic method of energy interchange among its members. Under this arrangement, PJM energy is exchanged among PJM member utilities at a price which represents the average of the producer's cost of generating the electricity dispatched and the buyer's replacement cost, or the cost avoided by making the purchase.
The maximum PJM demand of 46,429 MW occurred on July 8, 1993 when PJM's installed capacity (summer rating) was 55,440 MW. The Company's installed capacity for 1994-97 is expected to be sufficient to supply its PJM reserve margin share during that period.
The Company has made arrangements for the purchase of other companies' power during 1994. The source of the amount reserved each week depends on the availability of excess coal-fired capacity, PJM's import capability from these companies and the Company's economic need for additional power.
The Company's nuclear energy is generated by Limerick Generating Station (Limerick) Units No. 1 and No. 2 and Peach Bottom Atomic Power
Station (Peach Bottom) Units No. 2 and No. 3, which are operated by the Company, and by Salem Generating Station (Salem) Units No. 1 and No. 2, which are operated by Public Service Electric and Gas Company (PSE&G). The Company owns 100% of Limerick, 42.49% of Peach Bottom and 42.59% of Salem. Limerick Units No. 1 and No. 2 each has a capacity of 1,055 MW; Peach Bottom Unit No. 2 has a capacity of 1,051 MW, of which the Company is entitled to 447 MW; Peach Bottom Unit No. 3 has a capacity of 1,035 MW, of which the Company is entitled to 439 MW; and Salem Units No. 1 and No. 2 each has a capacity of 1,106 MW, of which the Company is entitled to 471 MW of each unit.
The Price-Anderson Act, as amended (Price-Anderson Act), sets the limit of liability of approximately $9.4 billion for claims that could arise from an incident involving any licensed nuclear facility in the nation. The limit is subject to increase to reflect the effects of inflation and changes in the number of licensed reactors. All utilities with nuclear generating units, including the Company, have obtained coverage for these potential claims through a combination of private insurances of $200 million and mandatory participation in a financial protection pool. Under the Price-Anderson Act, all nuclear reactor licensees can be assessed up to $76 million per reactor per incident, payable at no more than $10 million per reactor per incident per year. This assessment is subject to inflation, state premium taxes and an additional surcharge of 5% if the total amount of claims and legal costs exceeds the basic assessment. If the damages from an incident at a licensed nuclear facility exceed $9.4 billion, the President of the United States is to submit to Congress a plan for providing additional compensation to the injured parties. Congress could impose further revenue-raising measures on the nuclear industry to pay claims. The Price-Anderson Act and the extensive regulation of nuclear safety by the NRC do not preempt claims under state law for personal, property or punitive damages related to radiation hazards.
Although the NRC requires the maintenance of property insurance on nuclear power plants in the amount of $1.06 billion or the amount available from private sources, whichever is less, the Company maintains coverage in the amount of its $2.75 billion proportionate share for each station. The Company's insurance policies provide coverage for decontamination liability expense, premature decommissioning, and loss or damage to its nuclear facilities. These policies require that insurance proceeds first be applied to assure that the facility, following an accident, is in a safe and stable condition and can be maintained in such condition. Within 30 days of stablizing the reactor, the licensee must submit a report to the NRC which provides a clean-up plan including the identification of all clean-up operations necessary to decontaminate the reactor to either permit the resumption of operations or decommissioning of the facility. Under the Company's insurance policies, proceeds not already expended to place the reactor in a stable condition must be used to decontaminate the facility. If the decision is made to decommission the facility, a portion of the insurance proceeds must be allocated to a fund which the Company is required by the NRC to maintain to provide funds for decommissioning the facility. These proceeds would be paid to the fund to make up any difference between the amount of money in the fund at the time of the early decommissioning and the amount that would be in the fund if contributions had been made over the normal life
of the facility. The Company is unable to predict what effect these requirements may have on when insurance proceeds would be made available to the Company for the Company's bondholders and the amount of such proceeds which would be available. Under the terms of the various insurance agreements, the Company could be assessed up to $35 million for losses incurred at any plant insured by the insurance companies. The Company is self-insured to the extent that any losses may exceed the amount of insurance maintained. Any such losses, if not recovered through the ratemaking process, could have a material adverse effect on the Company's financial condition.
The Company is a member of an industry mutual insurance company which provides replacement power cost insurance in the event of a major accidental outage at a nuclear station. The policy contains a twenty-one week waiting period before recovery of costs can commence. The premium for this coverage is subject to an assessment for adverse loss experience. The Company's maximum share of any assessment is $17 million per year.
NRC regulations require that licensees of nuclear generating facilities must demonstrate that funds will be available in certain minimum amounts, established by a formula provided in the regulations, at the end of the life of the facility to decommission the facility. The PUC, based on estimates of decommissioning costs for each of the nuclear facilities in which the Company has an ownership interest, permits the Company to collect from its customers and deposit in segregated accounts amounts which, together with earnings thereon, will be necessary to decommission such nuclear facilities. The Company's ownership portion of decommissioning costs is approximately $643 million, expressed in 1990 dollars, which the Company believes would be substantially unchanged at December 31, 1993. The Company believes that the ultimate cost of decommissioning these facilities will continue to be recoverable through rates, but such recovery is not assured.
Limerick Generating Station
Limerick Unit No. 1 achieved a capacity factor of 95% in 1993 and 68% in 1992. Limerick Unit No. 2 achieved a capacity factor of 81% in 1993 and 91% in 1992. Limerick Units No. 1 and No. 2 are each on a 24-month refueling cycle. The last refueling outages for Units No. 1 and No. 2 were in 1994 and 1993, respectively.
On November 5, 1993, the NRC issued its periodic Systematic Assessment of Licensee Performance (SALP) Report for Limerick for the period March 15, 1992 to September 25, 1993. The Report was issued under the revised SALP process in which the number of assessment areas has been reduced from seven to four: Operations, Engineering, Maintenance, and Plant Support. The area of Plant Support includes: radiological controls, security, emergency preparedness, fire protection, chemistry and housekeeping. Limerick received ratings of "1," the highest of the three rating categories, in the two functional areas of Operations and Engineering. The areas of Maintenance and Plant Support received ratings of "2." The NRC stated that overall, it observed an excellent level of performance at Limerick. It noted continued strong performance in the Operations and Engineering areas and improvement in the Maintenance area. The NRC noted, however, that in the Maintenance area, personnel errors, a weakness from
the last SALP period, continued throughout the SALP period. Although the NRC recognized the implementation of initiatives by the Company to improve maintenance performance, it stated that such initiatives had not been in place long enough to be judged effective. In the area of Plant Support, the NRC stated that security, emergency preparedness, fire protection, chemistry and housekeeping continue to be very effective and contributed to safe plant performance. The NRC noted, however, performance weaknesses in the radiation controls area through the SALP period. The Company has taken and is taking actions to address the weaknesses discussed in the SALP Report.
By letter dated December 8, 1992, the NRC imposed a civil penalty of $25,000 on the Company based upon a decision by a United States Department of Labor Administrative Law Judge (ALJ) that the Company's security subcontractor unlawfully discriminated against one of its former employees. The ALJ concluded that the employee was required to undergo a psychological evaluation and subsequently was discharged by the security subcontractor in retaliation for raising safety concerns regarding security operations at Limerick. The security subcontractor is appealing the decision of the ALJ to the Secretary of Labor. The Company has not paid the NRC penalty pending the final decision in the matter.
On July 24, 1992, the NRC issued an information notice alerting utilities owning boiling water reactors (BWRs) to potential inaccuracies in water-level instrumentation during and after rapid depressurization events. On May 28, 1993, the NRC issued a bulletin requesting utilities owning BWRs to, among other things, install certain hardware modifications at the next cold shutdown of the BWR after July 30, 1993 to ensure accurate functioning of the water-level instrumentation. These hardware modifications were made on Peach Bottom Unit No. 2 in August 1993, Peach Bottom Unit No. 3 in November 1993 and Limerick Unit No. 1 in September 1993. The hardware modifications for Limerick Unit No. 2 will be made during the next cold shutdown of that unit.
The NRC has raised concerns that the Thermo-Lag 330 fire barrier systems used to protect cables and equipment may not provide the necessary level of fire protection and requested licensees to describe short- and long-term measures being taken to address this concern. The Company has informed the NRC that it has taken short-term compensatory actions to address the inadequacies of the Thermo-Lag barriers installed at Limerick and Peach Bottom and is participating in an industry-coordinated program to provide long-term corrective solutions. By letter dated December 21, 1992, the NRC stated that the Company's interim actions were acceptable. By letter dated December 22, 1993, the NRC requested additional information on the Company's long-term measures to address Thermo-Lag 330 fire barrier issues. The Company provided a response outlining its Thermo-Lag program and committing to provide a status report to the NRC by September 30, 1994. The Company cannot predict, at this time, what effect this matter will have on the operations of Limerick and Peach Bottom.
Water for the operation of Limerick is drawn from the Schuylkill River adjacent to Limerick and from the Perkiomen Creek, a tributary of the Schuylkill River. During certain periods of the year, generally the summer months but possibly for as much as six months or more in some years, the Company would not be able to operate Limerick without the use of
supplemental cooling water due to existing regulatory water withdrawal constraints applicable to the Schuylkill River and the Perkiomen Creek. Supplemental cooling water for Limerick is provided by a supplemental cooling water system which draws water from the Delaware River. The supplemental cooling water system for Limerick includes the following components: (1) the Point Pleasant Pumping Station (to withdraw water from the Delaware River) and a two and one-half-mile transmission main from the Point Pleasant Pumping Station to the Bradshaw Reservoir (Point Pleasant Project); (2) the Bradshaw Reservoir, a 25-million-gallon reservoir and pumping station which receives water from the Point Pleasant Project and acts as a dividing point for water for Limerick and for the public supply systems of two Montgomery County water authorities; (3) a seven-mile pipeline between the Bradshaw Reservoir and the east branch of the Perkiomen Creek (East Branch); (4) a water treatment facility to provide disinfection of Delaware River water; (5) approximately 24 miles of the East Branch and the main branch of the Perkiomen Creek; (6) a pumping station on the main branch of the Perkiomen Creek; and (7) an eight-mile transmission main from the pumping station on the Perkiomen Creek to Limerick.
Opposition to the Point Pleasant Project from various groups, including Bucks County and the Neshaminy Water Resources Authority (NWRA), a municipal authority created by Bucks County which had contracted to construct the Point Pleasant Project, resulted in protracted litigation in the Court of Common Pleas of Bucks County (Court of Common Pleas) and numerous appeals of the decisions of that court. In May 1988, the Bucks County Commissioners voted to end their opposition to the Point Pleasant Project and enacted an ordinance to enable Bucks County to acquire and manage the NWRA's projects, including the Point Pleasant Project. On May 26, 1988, in an action brought by Bucks County against the NWRA and its board members to enforce the ordinance, the Court of Common Pleas ordered the NWRA to transfer its projects, including the Point Pleasant Project, to Bucks County. Certain intervenors appealed to the Commonwealth Court, which dismissed the appeal on procedural grounds. The intervenors have filed a petition in the Court of Common Pleas to cure the procedural defect.
All permits for the construction and operation of the supplemental cooling water system have been obtained. As described below, the issuances of certain permits have been appealed. Certain of the permits relating to operation of the system must be renewed periodically.
On July 14, 1988, the PDER issued a National Pollutant Discharge Elimination System (NPDES) permit to the Company relating to the discharge of Delaware River water into the East Branch. The Company filed an appeal with respect to the temperature constraints and the limitations on discharges of certain impurities of the NPDES permit with the Environmental Hearing Board (EHB) on August 12, 1988. Certain environmental groups also filed permit appeals with the EHB. In order to comply with the conditions of its NPDES permit, the Company installed a water treatment facility to provide seasonal cooling and disinfection of the Delaware River water discharged into the East Branch. On March 31, 1992, the Company and PDER agreed to a settlement of the Company's appeal by entering into a Consent Adjudication, which is subject to approval by the EHB. The Consent Adjudication would resolve all issues in the
Company's appeal but would not affect the appeal by certain environmental groups from the NPDES permit. No action on the Company's Consent Adjudication has been taken by the EHB.
In July 1993, the PDER reissued the Company's NPDES permit. The reissued permit has conditions that are in certain instances less stringent than those set forth in the original permit.
On February 12, 1988, the PDER extended various existing permits and issued new stream encroachment permits and water allocation permits with respect to the supplemental cooling water system. Intervenors appealed the February 12, 1988 order to the EHB, which dismissed all appeals except certain appeals relating to the erosive impact of the supplemental cooling water system on the East Branch. These appeals have been stayed pending disposition of other litigation concerning the erosion issue, which was concluded in April 1992. In addition, appeals by an intervenor from interim permit extension decisions of the PDER on June 26, 1987 and an appeal of a 1982 water quality certification remain pending before the EHB but have been inactive.
The Company has also entered into an agreement which expires on December 31, 1994 with a municipality to secure a backup source of water for the interim operation of Limerick should water from the supplemental cooling water system not be available; however, this backup source is capable of providing only enough cooling water to operate both Limerick units simultaneously at 70% of rated capacity for short periods of time.
Peach Bottom Atomic Power Station
Peach Bottom Unit No. 2 achieved a capacity factor of 84% in 1993 and 61% in 1992. Peach Bottom Unit No. 3 achieved a capacity factor of 70% in 1993 and 78% in 1992. Peach Bottom Units No. 2 and No. 3 are each on a 24-month refueling cycle. The last refueling outages for Units No. 2 and No. 3 were in 1992 and 1993, respectively.
On March 19, 1993, the NRC issued its periodic SALP Report on the performance of activities at Peach Bottom for the period August 4, 1991 through October 31, 1992. Peach Bottom received ratings of "1" in the area of Emergency Preparedness and the area of Security and Safeguards. The areas of Plant Operations and Radiological Controls received ratings of "2, Improving." Each of the other three functional areas (Maintenance/Surveillance; Engineering/Technical Support; and Safety Assessment/Quality Verification) received ratings of "2." Except for the ratings in the areas of Plant Operations and Radiological Controls (each previously rated "2"), these were the same ratings as those received in the prior SALP Report. The SALP Report stated that management continued to maintain a strong safety perspective throughout the assessment period and fostered broad-based performance improvements that led to stronger programs in most functional areas. The SALP Report further stated that many of the programmatic weaknesses identified during the previous assessment period have either been eliminated or performance has been improved. For example, the SALP Report stated that fundamental problems with the quality of root-cause analysis noted during the last two periods have been resolved and that Peach Bottom's root-cause analysis capabilities now constitute a strength. In addition, the SALP Report
stated that licensed operators staffing and training continued to strengthen, contributing to improved Plant Operations performance. The SALP Report noted, however, that while overall progress in improving performance was clearly evident throughout the period, several weaknesses warranting continued management attention were identified. Among the areas identified for improvement were plant performance monitoring and engineering and technical support.
During 1983 outages, cracks in the piping of the residual heat removal and reactor recirculating water systems were discovered at Peach Bottom Unit No. 3 resulting from a generic problem with BWRs. Repairs, which involved the replacement of piping, required extended outages at the Unit. In February 1989, the Company, on behalf of the co-owners of Peach Bottom, filed a proof of loss with Nuclear Electric Insurance Limited (NEIL) for replacement power costs associated with Unit No. 3 outages. On January 19, 1993, the arbitrators issued a decision in favor of NEIL and denied the Company's claim. On April 19, 1993, the Company filed a motion in the United States District Court for the Southern District of New York to vacate the arbitration decision.
On May 21, 1992, the Company filed a request with the NRC to amend its Facility Operating Licenses for Peach Bottom Units No. 2 and No. 3 to extend the expiration dates to August 2013 and July 2014, respectively, 40 years from the dates of issuance. The current operating licenses expire 40 years from the dates of issuance of the construction permits for the Units. If the NRC grants the Company's request, the operating license for Unit No. 2 will be extended approximately five years, six months and the operating license for Unit No. 3 will be extended approximately six years, five months.
By letter dated June 23, 1993, the Company submitted a request to the NRC to rerate the authorized maximum reactor core power levels of both Peach Bottom units by 5% to 3,458 megawatts thermal (Mwt) from the current limits of 3,293 Mwt. The analyses and evaluations supporting this request were completed using generic guidelines approved by the NRC. If the request is approved, the associated hardware changes will be made on Unit No. 2 during the planned fall 1994 refueling outage and on Unit No. 3 during the planned fall 1995 refueling outage.
In addition to the matters discussed above, see "Electric Operations- Limerick Generating Station" for a discussion of certain matters which affect both Peach Bottom and Limerick.
Salem Generating Station
Salem Unit No. 1 achieved a capacity factor of 60% in 1993 and 54% in 1992. Salem Unit No. 2 achieved a capacity factor of 57% in 1993 and 49% in 1992. Salem Units No. 1 and No. 2 are each on an 18-month refueling cycle. The last refueling outages for Units No. 1 and No. 2 were in 1993.
The Company has been informed by PSE&G that on September 1, 1993, the NRC furnished PSE&G with its periodic SALP Report for Salem. The operating period reviewed was from December 29, 1991 through June 19, 1993. Salem received ratings of "1" in the areas of Radiological Controls and Security. The area of Emergency Preparedness received a rating of "1,
Declining." The areas of Plant Operations; Maintenance/ Surveillance; Engineering/Technical Support; and Safety Assessment/ Quality Verification received ratings of "2." The NRC concluded that PSE&G's performance during the period was good and noted an improvement over the last rating period in the area of Radiological Controls. The NRC noted, however, that Salem had a number of substantial operational challenges during the period and that additional management attention is warranted to reduce the frequency of such operational challenges.
The Company has been informed by PSE&G that, by letter dated March 9, 1994, the NRC imposed a civil penalty of $50,000 for eight violations for failure to follow procedures at Salem related to the control of maintenance of work activities. The NRC stated that, while none of the violations were significant from a nuclear safety perspective, some of the violations demonstrated the potential to cause physical harm to individuals. In addition, the NRC stated that collectively, the violations demonstrated that weaknesses exist in the maintenance and control of work process activities, which could, under other circumstances, adversely affect the operability of safety related equipment at Salem. The NRC required PSE&G to respond to the alleged violations within 30 days and document the specific corrective actions that have been and will be taken.
In order to improve Salem's materiel condition, plant and personnel performance and address the NRC's concerns expressed in its October 1990 SALP Report, the Salem owners, including the Company, are in the process of augmenting plans to improve Salem's materiel condition, upgrade procedures and enhance personnel performance. The Company's share of the plan's capital requirements for 1994 and for 1995-97 are reflected in the Company's most recent estimates of capital expenditures for plant additions and improvements for such periods. The planned improvements are being managed by PSE&G as a discrete project and are expected to coincide with plant operating schedules.
In addition to the matters discussed above, see "Environmental Regulations-Water" for a discussion of possible installation of cooling towers at Salem.
Fuel
The following table shows the Company's sources of electric output for 1993 and as estimated for 1994:
The following table shows the Company's average fuel cost used to generate electricity:
---------- (1) British thermal unit.
(2) Reflects reclassification of spent-fuel cost for comparative purposes.
Nuclear
The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore; the conversion of uranium concentrates
to uranium hexafluoride; the enrichment of the uranium hexafluoride; the fabrication of fuel assemblies; and the utilization of the nuclear fuel in the generating station reactor. The Company has contracts for uranium concentrates which will satisfy the fuel requirements of Limerick and Peach Bottom through 1996. The Company's contracts for uranium concentrates are allocated to Limerick and Peach Bottom on an as-needed basis. PSE&G has informed the Company that it presently has under contract sufficient uranium concentrates to fully meet the current projected requirements for Salem through 2000 and 60% of the requirements through 2002. The following table summarizes the years through which the Company and PSE&G have contracted for the other segments of the nuclear fuel supply cycle.
---------- (1) The Company has exercised its option to remain uncommitted under the United States Enrichment Corporation (USEC) enrichment contract from 2000 to 2002. This action, however, does not exclude USEC enrichment services from consideration in this period. The Company does not anticipate any difficulties in obtaining necessary enrichment services for its Limerick and Peach Bottom Units.
(2) Represents 100% of enrichment requirements through 1998 and 30% through 2001. Similar to the Company's actions discussed in note (1) above, the Company has been informed by PSE&G that PSE&G has exercised its option to remain uncommitted under its USEC enrichment contract from 1999 to 2002.
On March 1, 1993, the Company entered into an agreement with the Long Island Power Authority (LIPA) and other parties, subsequently revised on September 14, 1993, to receive $46 million as compensation for accepting slightly irradiated fuel from the Shoreham Nuclear Power Station on Long Island, New York, for use at Limerick. The Company is to receive the $46 million in installments as the shipments of nuclear fuel are accepted. The first of the 33 shipments arrived at Limerick on September 28, 1993. Nineteen shipments of fuel were completed prior to the suspension of shipments to accommodate the refueling outage of Limerick Unit No. 1. Shipments of the remaining fuel are scheduled to resume after completion of the refueling outage. The Company estimates that the acquisition of the fuel will result in benefits to the Company's customers of $70 million over the next 12 to 15 years due to reduced fuel-purchase requirements. The fuel will be stored at Limerick's spent-fuel pool pending its use at Limerick beginning in 1994 and extending beyond 2005. On September 21, 1993, the State of New Jersey filed suit in the United States District Court for the District of New Jersey (New Jersey District Court) seeking a
stay of shipments of fuel because of alleged failures of federal agencies to fully review the proposed shipping plan under the National Environmental Policy Act (NEPA) and the Coastal Zone Management Act (CZMA). The New Jersey District Court refused to halt the shipments and New Jersey has appealed to the United States Court of Appeals for the Third Circuit (Appeals Court). The Appeals Court affirmed the New Jersey District Court decision to dismiss the suit and subsequently denied a request for rehearing. New Jersey has also requested that the NRC halt shipments until the NRC further reviews the fuel transfer under the NEPA and CZMA. The NRC has refused these requests.
The commercial reprocessing and recycling of the plutonium produced in the United States nuclear power programs have been delayed indefinitely. There are no commercial facilities for the reprocessing of spent nuclear fuel currently in operation in the United States, nor has the NRC licensed any such facilities. The spent-fuel storage pools for Limerick have sufficient capacity to permit storage through 1999. Reracking of the spent-fuel storage pools at Limerick, which will extend storage capacity to approximately 2010, is in the preliminary stages. The new configuration will be designed to accommodate rod consolidation. Spent-fuel racks at Peach Bottom have storage capacity until 1998 for Unit No. 2 and 1999 for Unit No. 3. Options for expansion of storage capacity at both Limerick and Peach Bottom beyond the pertinent dates, including the viability of rod consolidation, are being investigated. The Company has been informed by PSE&G that the spent-fuel storage capacity at Salem will permit storage of spent fuel through March 1998 for Salem Unit No. 1 and March 2002 for Salem Unit No. 2. PSE&G has developed an integrated strategy to meet the longer-term spent-fuel storage needs for Salem. PSE&G plans to replace the existing high-density racks in the spent-fuel storage pools of Salem Units No. 1 and No. 2 with maximum density racks. The reracking project commenced in early 1992 and is expected to extend the storage capability of Salem Units No. 1 and No. 2 through March 2008 and March 2012, respectively.
Under the Nuclear Waste Policy Act of 1982 (NWPA), the federal government was to begin accepting spent fuel for permanent off-site storage no later than 1998. The DOE has stated that there is no legal obligation under the NWPA to begin accepting spent fuel absent an operational repository or other facility constructed under the NWPA. The DOE acknowledges, however, that it may have created the expectation of such a commitment on the part of utilities by issuing certain regulations and projected waste acceptance schedules. The DOE has stated that it will not be able to open a permanent, high-level nuclear waste repository until 2010, at the earliest. The DOE stated that the delay was a result of its seeking new data about the suitability of the proposed repository site at Yucca Mountain, Nevada, opposition to this location for the repository and the DOE's revision of its civilian nuclear waste program. The DOE stated that it would seek legislation from Congress for the construction of a temporary storage facility which would accept spent nuclear fuel from utilities beginning in 1998 or soon thereafter. Although progress is being made at Yucca Mountain and several communities have expressed interest in providing a temporary storage site, the Company cannot predict when the temporary federal storage facilities or permanent repository will become available. The DOE is exploring options to address delays in the currently projected waste acceptance schedules. The options under consideration by
the DOE include offsetting a portion of the financial burden associated with the costs of continued on-site storage of spent fuel after 1998 and the issuance by the DOE to utilities of multi-purpose canisters for on-site storage. Under the NWPA, the DOE is authorized to assess utilities for the cost of nuclear fuel disposal. The current cost of such disposal is one mill per kWh of net nuclear generation. The 1993 charge collected by the Company from its customers for spent-fuel disposal was $23 million. The DOE may revise this charge as necessary for full-cost recovery of nuclear fuel disposal. The National Energy Policy Act of 1992 (Energy Act) states, among other things, that utilities with nuclear reactors must pay for the decommissioning and decontamination of the DOE nuclear fuel enrichment facilities. The total costs to domestic utilities are estimated to be $150 million per year for 15 years, of which the Company's share is $5 million per year. The Energy Act provides that these costs are to be recoverable in the same manner as other fuel costs. The Company has recorded the liability and a related regulatory asset of $69 million for such costs at December 31, 1993. The Company is currently recovering these costs through the Energy Cost Adjustment (ECA). The Company believes that the ultimate costs of decommissioning and decontamination, spent-fuel disposal and any assessment under the Energy Act will continue to be recoverable through rates, although such recovery is not assured.
Coal
The Company has a 20.99% ownership interest in Keystone Station (Keystone) and a 20.72% ownership interest in Conemaugh Station (Conemaugh), coal-fired, mine-mouth generating stations in western Pennsylvania, operated by Pennsylvania Electric Company. A majority of Keystone's fuel requirements is supplied by one coal company under a contract which expires on December 31, 2004. The contract calls for varying amounts of coal purchases as follows: between 3,000,000 and 3,500,000 tons for each of the years 1994 through 1999; and a total of 6,500,000 tons for the years 2000 through 2004. At December 31, 1993, approximately 63% of Conemaugh's fuel requirements were secured by a long-term contract and several short-term contracts. The Company customarily enters into medium-term contracts for a significant portion of its coal requirements and makes spot purchases for the balance of coal required by its Philadelphia-area, coal-fired units at Eddystone Station (Eddystone) and Cromby Station (Cromby). At January 1, 1994, the Company had contracts with two suppliers for 600,000 tons per year or approximately 55% of expected annual requirements. One contract expires on September 30, 1994 and the other expires on December 31, 1994 with an option to extend for one additional year if the Company and the supplier so agree.
The coal requirements of each station not covered by existing contracts are met through additional short-term contracts or spot purchases from local suppliers.
Oil The Company customarily enters into yearly purchase orders with its various oil suppliers for the bulk of its requirements and makes spot purchases for the balance. At present, the Company's purchase orders are
sufficient to meet the estimated residual fuel oil needs of its oil-fired generating units through April 1994, when current orders end and new yearly orders begin. Purchase orders for distillate fuel oil are expected to meet the Company's needs through September 1994, when current orders end and new yearly orders begin.
Natural Gas
The Company supplies natural gas for Cromby Unit No. 2 under a City Gate Sales tariff approved by the PUC and through spot purchases made on the open market. A limited amount of natural gas is used in auxiliary boilers and pollution control equipment at Eddystone. In 1993, the Company began converting Eddystone Units No. 3 and No. 4 to allow the use of oil or natural gas.
Gas Operations
During 1993, 9.6% of the Company's operating revenues and 5.7% of its operating income were from gas operations. Gas sales and operating revenues for 1993 by classes of customers are set forth below:
The Company's natural gas supply is provided by purchases from a number of suppliers for terms ranging from 2 to 10 years. These purchases are delivered under several long-term firm transportation contracts with Texas Eastern Transmission Corporation (Texas Eastern) and Transcontinental Gas Pipe Line Corporation (Transcontinental). The Company's aggregate annual entitlement under these firm contracts is 69.3 million dekatherms. Peak gas is provided by the Company's liquefied natural gas facility and propane-air plant (see "ITEM 2.


ITEM 2. PROPERTIES
The principal plants and properties of the Company are subject to the lien of the Mortgage under which the Company's First and Refunding Mortgage Bonds are issued.
The following table sets forth the Company's net electric generating capacity by station at December 31, 1993:
---------- (1) Summer rating. (2) Company portion. (3) Retirement dates are under on-going review by the Company. Current plans call for the continued operation of these plants beyond 1994.
The following table sets forth the Company's major transmission and distribution lines in service at December 31, 1993:
At December 31, 1993, the Company's principal electric distribution system included 12,294 pole-line miles of overhead lines and 19,595 cable miles of underground cables.
The Company has undertaken a 10-year program to implement a 34 Kv distribution system for a large portion of outlying suburban areas. These areas are now primarily served by a combination of 4 Kv distribution circuits, which are being phased out, and direct connections to 34 Kv subtransmission lines, which are being converted to 34 Kv distribution circuits. The new system is designed to improve the Company's ability to meet the growing load requirements of suburban areas, improve system reliability and reduce service interruptions.
The following table sets forth the Company's gas pipeline miles at December 31, 1993:
Pipeline Miles -------------- Transmission................................................ 35 Distribution................................................ 5,285 Service Piping.............................................. 4,448 ----- Total................................................... 9,768 =====
The Company has a liquefied natural gas facility located in West Conshohocken, Pennsylvania which has a storage capacity of 1,200,000 mcf and a sendout capacity of 200,000 mcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 1,980,000 gallons and a peaking capability of 30,000 mcf/day. In addition, the Company owns 19 natural gas city gate stations at various locations throughout its gas service territory.
The Company owns an office building in downtown Philadelphia, in which it maintains its headquarters, and also owns or leases elsewhere in its
service area a number of properties which are used for office, service and other purposes. Information regarding rental and lease commitments is incorporated herein by reference to note 14 of Notes to Consolidated Financial Statements included in the Company's Annual Report to Shareholders for the year 1993.
The Company maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. Although it is impossible to determine the total amount of the loss that may result from an occurrence at a nuclear generating station, the Company maintains its $2.75 billion proportionate share for each station. Under the terms of the various insurance agreements, the Company could be assessed up to $35 million for property losses incurred at any plant insured by the insurance companies (see "ITEM 1. BUSINESS-Electric Operations"). The Company is self-insured to the extent that any losses may exceed the amount of insurance maintained. Any such losses, if not recovered through the ratemaking process, could have a material adverse effect on the Company's financial condition.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
On April 11, 1991, 33 former employees of the Company filed an amended class action suit against the Company in the Eastern District Court on behalf of approximately 141 persons who retired from the Company between January and April 1990. The lawsuit, filed under the Employee Retirement Income Security Act (ERISA), alleges that the Company fraudulently and/or negligently misrepresented or concealed facts concerning the Company's 1990 Early Retirement Plan and thus induced the plaintiffs to retire or not to defer retirement immediately before the initiation of the Early Retirement Plan, thereby depriving the plaintiffs of substantial pension and salary benefits. On June 6, 1991, the plaintiffs filed amended complaints adding additional plaintiffs. The lawsuit names the Company, the Company's Service Annuity Plan (SAP) and two Company officers as defendants. The plaintiffs seek approximately $20 million in damages representing, among other things, increased pension benefits and nine months' salary pursuant to the terms of the Early Retirement Plan, as well as punitive damages. On July 29, 1992, the Eastern District Court granted the Company's motion for summary judgment and entered judgment in favor of the Company. On May 26, 1993, the Appeals Court reversed the grant of summary judgment and remanded the case to the Eastern District Court. On October 18, 1993, the Company filed a petition for a writ of certiorari to the United States Supreme Court, asking the Court to hear the case, which petition was denied. The ultimate outcome of this matter is not expected to have a material adverse effect on the Company's financial condition.
On May 2, 1991, 37 former employees of the Company filed an amended class action suit against the Company, the SAP and three former Company officers in the Eastern District Court on behalf of 147 former employees who retired from the Company from January through June 1987. The lawsuit was filed under ERISA and concerns the August 1, 1987 amendment to the SAP. The plaintiffs claim that the Company concealed or misrepresented the fact that the amendment to the SAP was planned to increase retirement benefits and, as a consequence, they retired prior to the amendment to the SAP and were deprived of significant retirement benefits. The complaint does not specify any dollar amount of damages. On July 29, 1992, the Eastern District Court granted the Company's motion for summary judgment
and entered judgment in favor of the Company. On May 26, 1993, the Appeals Court reversed the grant of summary judgment and remanded the case to the Eastern District Court. On October 18, 1993, the Company filed a petition for a writ of certiorari to the United States Supreme Court, asking the Court to hear the case, which petition was denied. The ultimate outcome of this matter is not expected to have a material adverse effect on the Company's financial condition.
On May 25, 1993, the Company received a letter from attorneys on behalf of a shareholder demanding that the Company's Board of Directors commence legal action against certain Company officers and directors with respect to the Company's credit and collections practices. The basis of the demand is the findings and conclusions contained in the Credit and Collection section of the May 1991 PUC Management Audit Report prepared by Ernst & Young. At its June 28, 1993 meeting, the Board of Directors appointed a Special Committee of Directors to consider whether such legal action is the best interests of the Company and its shareholders. On March 14, 1994, upon the recommendation of the report of the Special Committee, the Board of Directors adopted a resolution refusing the shareholder demand set forth in the May 25, 1993 demand letter, and authorizing and directing officers of the Company to take all steps necessary to terminate the derivative suit discussed below.
On July 26, 1993, attorneys on behalf of two shareholders filed a shareholder derivative action in the Court of Common Pleas of Philadelphia County against several of the Company's present and former officers alleging mismanagement, waste of corporate assets and breach of fiduciary duty in connection with the Company's credit and collections practices. A similar suit by the same plaintiffs previously had been withdrawn while on appeal after dismissal by the court for failure to first serve a demand on the Company's Board of Directors. This action is also based on the findings and conclusions contained in the Credit and Collection section of the May 1991 PUC Management Audit Report prepared by Ernst & Young. The plaintiffs seek, among other things, an unspecified amount of damages and the awarding to the plaintiffs of the costs and disbursements of the action, including attorneys' fees. On September 30, 1993, the Company filed preliminary objections asking that the action be dismissed on the grounds that it is premature. On December 6, 1993, the court denied the Company's preliminary objections. Any monetary damages which may be recovered, net of expenses, would be paid to the Company because the lawsuit is brought derivatively by shareholders on behalf of the Company.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is listed on the New York and Philadelphia Stock Exchanges. At January 31, 1994, there were 219,644 owners of record of the Company's common stock. The information with respect to the prices of and dividends on the Company's common stock for each quarterly period during 1992 and 1993 is incorporated herein by reference to "Operating Statistics" in the Company's Annual Report to Shareholders for the year 1993.
The book value of the Company's common stock at December 31, 1993 was $19.25 per share.
Dividends may be declared on common stock out of funds legally available for dividends whenever full dividends on all series of preferred stock outstanding at the time have been paid or declared and set apart for payment for all past quarter-yearly dividend periods. No dividends may be declared on common stock, however, at any time when the Company has failed to satisfy the sinking fund obligations with respect to certain series of the Company's preferred stock. Future dividends on common stock will depend upon earnings, the Company's financial condition and other factors, including the availability of cash.
The Company's Articles prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of the Company represented by its common stock together with its Other Paid-In Capital and Retained Earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred stock. At December 31, 1993, such capital ($4.26 billion) amounted to about 7 times the liquidating value of the outstanding preferred stock ($609 million).
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data for each of the last five years for the Company and its subsidiaries is incorporated herein by reference to "Financial Statistics" and "Operating Statistics" in the Company's Annual Report to Shareholders for the year 1993.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information with respect to this caption is incorporated herein by reference to "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the Company's Annual Report to Shareholders for the year 1993.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information with respect to this caption is incorporated herein by reference to "Consolidated Financial Statements" and "Financial Statistics" in the Company's Annual Report to Shareholders for the year 1993.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.


ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Identification of Directors.
The information required for Directors is included in the Proxy Statement of the Company in connection with its 1994 Annual Meeting of Shareholders to be held April 13, 1994, under the heading "Proposal 1. Election of Directors" and is incorporated herein by reference.
(b) Identification of Executive Officers.
The information required for Executive Officers is set forth in "ITEM 1. BUSINESS-Executive Officers of the Registrant" of this Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information with respect to this caption is included in the Proxy Statement of the Company in connection with its 1994 Annual Meeting of Shareholders to be held April 13, 1994, under the heading "Proposal 1. Election of Directors" and is incorporated herein by reference.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information with respect to this caption is included in the Proxy Statement of the Company in connection with its 1994 Annual Meeting of Shareholders to be held April 13, 1994, under the heading "Proposal 1. Election of Directors" and is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information with respect to this caption is included in the Proxy Statement of the Company in connection with its 1994 Annual Meeting of Shareholders to be held April 13, 1994, under the heading "Proposal 1. Election of Directors" and is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Financial Statement Schedules
All other schedules are omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and notes thereto.
With the exception of the consolidated financial statements and the independent accountants' report listed in the above index and the information referred to in Items 1, 2, 5, 6, 7 and 8, all of which is included in the Company's Annual Report to Shareholders for the year 1993 and incorporated by reference into this Form 10-K Annual Report, the Annual Report to Shareholders for the year 1993 is not to be deemed "filed" as part of this Form 10-K.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and Board of Directors PECO Energy Company:
Our report on the consolidated financial statements of PECO Energy Company has been incorporated by reference in this Form 10-K from page 18 of the 1993 Annual Report to Shareholders of PECO Energy Company. In connection with our audits of such financial statements, we have also audited the related financial statement schedules listed in the index in Item 14 of this Form 10-K.
In our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information required to be included therein.
COOPERS & LYBRAND
2400 Eleven Penn Center Philadelphia, Pennsylvania January 31, 1994
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES SCHEDULE V-UTILITY PLANT (Thousands of Dollars) FOR THE YEAR ENDED DECEMBER 31, 1993
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES SCHEDULE V- UTILITY PLANT (Thousands of Dollars) FOR THE YEAR ENDED DECEMBER 31, 1992
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES SCHEDULE V-UTILITY PLANT (Thousands of Dollars) FOR THE YEAR ENDED DECEMBER 31, 1991
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES SCHEDULE VI-ACCUMULATED DEPRECIATION OF UTILITY PLANT (Thousands of Dollars) FOR THE YEAR ENDED DECEMBER 31, 1993
Depreciation charged to transportation ..................... (851) Amortization of anti-trust.................................. (16) Amortization of Conowingo Project relicensing costs......... 100 Limerick Unit No. 1 disallowance............................ (10,319) Limerick Unit No. 2 disallowance............................ (4,424) Amortization of Limerick Unit No. 1 declaratory order..................................................... 14,750 Amortization of Limerick 50% common facilities deferred depreciation and carrying charges................ 7,897 Amortization of nuclear design basis ....................... 1,460 -------- Depreciation charged to operating expenses (2)..............$424,952 ========
---------- (1) Other Changes Limerick disallowance............................ $(14,743) Removal cost net of salvage...................... (15,257) Amortization of Conowingo Project relicensing costs............................. 100 Interest on decommissioning funds................ 5,708 Miscellaneous.................................... (775) -------- Total Other Changes ......................... $(24,967) ========
(2) Includes the provision for decommissioning nuclear plants of $20,255.
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES SCHEDULE VI-ACCUMULATED DEPRECIATION OF UTILITY PLANT (Thousands of Dollars) FOR THE YEAR ENDED DECEMBER 31, 1992
Depreciation charged to transportation ..................... (452) Amortization of anti-trust.................................. (19) Amortization of Conowingo Project relicensing costs......... 100 Limerick Unit No. 1 disallowance............................ (10,319) Limerick Unit No. 2 disallowance............................ (4,424) Amortization of Limerick Unit No. 1 declaratory order....... 14,750 Amortization of Limerick 50% common facilities deferred depreciation and carrying charges................ 7,897 Amortization of nuclear design basis........................ 856 -------- Depreciation charged to operating expenses (2)..............$413,779 ========
---------- (1) Other Changes Limerick disallowance................................. $(14,743) Removal cost net of salvage........................... (17,456) Amortization of Conowingo Project relicensing costs... 100 Interest on decommissioning funds..................... 6,932 -------- Total Other Changes .............................. $(25,167) ========
(2) Includes the provision for decommissioning nuclear plants of $20,255.
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES SCHEDULE VI-ACCUMULATED DEPRECIATION OF UTILITY PLANT (Thousands of Dollars) FOR THE YEAR ENDED DECEMBER 31, 1991
Depreciation charged to transportation ..................... (632) Amortization of anti-trust.................................. (34) Amortization of Conowingo Project relicensing costs......... 100 Limerick Unit No. 1 disallowance............................ (10,319) Limerick Unit No. 2 disallowance............................ (4,424) Amortization of Limerick Unit No. 1 declaratory order....... 14,750 Amortization of Limerick 50% common facilities' deferred depreciation and carrying charges................ 7,897 Other....................................................... 18 -------- Depreciation charged to operating expenses (2)..............$400,572 ========
---------- (1) Other Changes: Limerick disallowances..................................$(14,743) Removal cost, net of salvage............................ (14,933) Amortization of Conowingo Project relicensing costs..... 100 Interest on decommissioning funds....................... 5,796 -------- Total Other Changes ................................$(23,780) ========
(2) Includes the provision for decommissioning nuclear plants of $20,027.
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES SCHEDULE VIII-VALUATION AND QUALIFYING ACCOUNTS (Thousands of Dollars)
Exhibits
Certain of the following exhibits have been filed with the Securities and Exchange Commission (Commission) pursuant to the requirements of the Acts administered by the Commission. Such exhibits are identified by the references following the listing of each such exhibit and are incorporated herein by reference under Rule 24 of the Commission's Rules of Practice. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the Company and its subsidiaries on a consolidated basis and the Company agrees to furnish a copy of any such instrument to the Commission upon request.
Exhibit No. Description - --------------------------
3-1 Amended and Restated Articles of Incorporation of PECO Energy Company. 3-2 Bylaws of the Company, adopted February 26, 1990 and amended January 24, 1994. 4-1 First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to the Company) and Fidelity Trust Company, Trustee (First Fidelity Bank, National Association, successor), (Registration No. 2-2881, Exhibit B-1). 4-2 Supplemental Indentures to the Company's First and Refunding Mortgage:
Dated as of File Reference Exhibit No. - ------------------------------------------------------------------------------ September 1, 1926 2-2881 B-1(a) May 1, 1927 2-2881 B-1(b) May 1, 1927 2-2881 B-1(c) November 1, 1927 2-2881 B-1(d) January 31, 1931 2-2881 B-1(e) February 1, 1931 2-2881 B-1(f) March 1, 1937 2-2881 B-1(g) December 1, 1941 2-4863 B-1(h) November 1, 1944 2-5472 B-1(i) December 1, 1946 2-6821 7-1(j) February 1, 1948 2-7381 7-1(k) January 1, 1952 2-9329 4(b)-13 May 1, 1953 2-10201 4(b)-14 December 1, 1953 2-10568 4(b)-15 April 1, 1955 2-11536 2(b)-16 September 1, 1957 2-13562 2(b)-17 May 1, 1958 2-14020 2(b)-18 December 1, 1958 2-14528 2(b)-19 October 1, 1959 2-15609 2(b)-20 May 1, 1964 2-25628 4(b)-21 October 15, 1966 2-25628 4(b)-22 June 1, 1967 2-26430 2(b)-23 October 1, 1967 2-28242 2(b)-23 March 1, 1968 2-34051 2(b)-24 September 10, 1968 2-34051 2(b)-25 August 15, 1969 2-35939 2(b)-26 February 1, 1970 2-37020 2(b)-27 May 1, 1970 2-38849 2(b)-28 December 15, 1970 2-41081 2(b)-29 August 1, 1971 2-42402 2(b)-30 December 15, 1971 2-44195 2(b)-31 June 15, 1972 2-46625 2(b)-32 January 15, 1973 2-49842 2(b)-33 January 15, 1974 2-49849 2(b)-34 October 15, 1974 2-51887 2(b)-35 April 15, 1975 2-54182 2(b)-36 August 1, 1975 2-55423 2(b)-37 March 1, 1976 2-56749 2(b)-38 August 1, 1976 2-58198 2(b)-39 February 1, 1977 2-58198 2(b)-40 March 15, 1977 2-59177 2(b)-41 July 15, 1977 2-60743 2(b)-42 March 15, 1978 2-65604 2(b)-43 October 15, 1979 2-69086 (b)(1)-49 October 15, 1980 2-72802 4-45 March 1, 1981 2-72802 4-46 March 1, 1981 2-72802 4-47 July 1, 1981 2-76238 4-48
Dated as of File Reference Exhibit No. - -----------------------------------------------------------------------------
September 15, 1981 2-76238 4-49 April 1, 1982 2-79269 4-50 October 1, 1982 2-83875 4-51 June 15, 1983 1983 Form 10-K 4-2(a) November 15, 1984 1984 Form 10-K 4-2(a) December 1, 1984 1984 Form 10-K 4-2(b) May 15, 1985 1985 Form 10-K 4-2(a) October 1, 1985 1985 Form 10-K 4-2(b) November 15, 1985 1985 Form 10-K 4-2(c) November 15, 1985 1985 Form 10-K 4-2(d) June 1, 1986 1986 Form 10-K 4-2(a) November 1, 1986 1986 Form 10-K 4-2(b) November 1, 1986 1986 Form 10-K 4-2(c) April 1, 1987 33-14613 4(c)-62 July 15, 1987 Form 8-K dated July 21, 1987 4(c)-63 July 15, 1987 Form 8-K dated July 21, 1987 4(c)-64 August 1, 1987 33-17438 4(c)-65 October 15, 1987 Form 8-K dated October 7, 1987 4(c)-66 October 15, 1987 Form 8-K dated October 7, 1987 4(c)-67 April 15, 1988 Form 8-K dated April 11, 1988 4(e)-68 April 15, 1988 Form 8-K dated April 11, 1988 4(e)-69 June 15, 1989 33-31289 4(e)-70 October 1, 1989 Form 8-K dated October 6, 1989 4(e)-71 October 1, 1989 Form 8-K dated October 6, 1989 4(e)-72 October 1, 1989 Form 8-K dated October 18, 1989 4(e)-73 October 15, 1990 1990 Form 10-K 4(e)-74 October 15, 1990 1990 Form 10-K 4(e)-75 April 1, 1991 1991 Form 10-K 4(e)-76 December 1, 1991 1991 Form 10-K 4(e)-77 January 15, 1992 Form 8-K dated January 27, 1992 4(e)-78 April 1, 1992 March 31, 1992 Form 10-Q 4(e)-79 April 1, 1992 March 31, 1992 Form 10-Q 4(e)-80 June 1, 1992 June 30, 1992 Form 10-Q 4(e)-81 June 1, 1992 June 30, 1992 Form 10-Q 4(e)-82 July 15, 1992 June 30, 1992 Form 10-Q 4(e)-83 September 1, 1992 1992 Form 10-K 4(e)-84 September 1, 1992 1992 Form 10-K 4(e)-85 March 1, 1993 1992 Form 10-K 4(e)-86 March 1, 1993 1992 Form 10-K 4(e)-87 May 1, 1993 March 31, 1993 Form 10-Q 4(e)-88 May 1, 1993 March 31, 1993 Form 10-Q 4(e)-89 May 1, 1993 March 31, 1993 Form 10-Q 4(e)-90 August 15, 1993 Form 8-A dated August 19, 1993 4(e)-91 August 15, 1993 Form 8-A dated August 19, 1993 4(e)-92 August 15, 1993 Form 8-A dated August 19, 1993 4(e)-93 November 1, 1993 Form 8-A dated October 27, 1993 4(e)-94 November 1, 1993 Form 8-A dated October 27, 1993 4(e)-95
4-3 Deposit Agreement with respect to $7.96 Cumulative Preferred Stock (Form 8-K dated October 20, 1992, Exhibit 4-5).
4-4 PECO Energy Company Dividend Reinvestment and Stock Purchase Plan, as amended January 28, 1994 (Post-Effective Amendment No. 1 to Registration No. 33-43523, Exhibit 28).
10-1 Pennsylvania-New Jersey-Maryland Interconnection Agreement dated September 26, 1956 (Registration No. 2-13340, Exhibit 13-40) and agreements supplemental thereto:
Dated as of File Reference Exhibit No. ----------------------------------------------------------------------------- March 1, 1965 2-38342 5-1(a) January 1, 1971 2-40368 5-1(b) June 1, 1974 2-51887 5-1(c) September 1, 1977 1989 Form 10-K 10-1(a) October 1, 1980 1989 Form 10-K 10-1(b) June 1, 1981 1989 Form 10-K 10-1(c)
10-2 Agreement, dated November 24, 1971, between Atlantic City Electric Company, Delmarva Power & Light Company, Public Service Electric and Gas Company and the Company for ownership of Salem Nuclear Generating Station (1988 Form 10-K, Exhibit 10-3); supplemental agreement dated September 1, 1975; and supplemental agreement dated January 26, 1977 (1991 Form 10-K, Exhibit 10-3).
10-3 Agreement, dated November 24, 1971, between Atlantic City Electric Company, Delmarva Power & Light Company, Public Service Electric and Gas Company and the Company for ownership of Peach Bottom Atomic Power Station; supplemental agreement dated September 1, 1975; and supplemental agreement dated January 26, 1977 (1988 Form 10-K, Exhibit 10-4).
10-4 Deferred Compensation and Supplemental Pension Benefit Plan (1981 Form 10-K, Exhibit 10-16).*
10-5 Philadelphia Electric Company Stock Price Appreciation Plan, effective June 1, 1988 (1988 Form 10-K, Exhibit 4-7).*
10-6 Philadelphia Electric Company 1989 Long-Term Incentive Plan (Registration No. 33-30317, Exhibit 28).*
12-1 Ratio of Earnings to Fixed Charges.
12-2 Ratio of Earnings to Combined Fixed Charges and Preferred Dividends.
13 Management's Discussion and Analysis of Financial Condition and Results of Operations, Consolidated Financial Statements, Notes to Consolidated Financial Statements, Financial Statistics, and Operating Statistics of the Annual Report to Shareholders for the year 1993.
22 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
24 Powers of Attorney.
---------- * Compensatory plans or arrangements in which directors or officers of the Company participate and which are not available to all employees.
Reports on Form 8-K
During the quarter ended December 31, 1993, the Company filed a Current Report on Form 8-K, dated December 28, 1993 reporting information under "ITEM 5. OTHER EVENTS" relating to the Company's name change.
Subsequent to December 31, 1993, the Company filed no Current Reports on Form 8-K.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant, PECO ENERGY COMPANY, has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Philadelphia, and Commonwealth of Pennsylvania, on the 16th day of March 1994.
PECO ENERGY COMPANY
By /s/ J. F. PAQUETTE, JR. ------------------------------------------ J. F. Paquette, Jr., Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this annual report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.