ITEM 1. BUSINESS
The Company
PECO Energy Company (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 Hydroelectric 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 63% of retail kilowatthour (kWh) sales are in the suburbs around Philadelphia and in northeastern Maryland, and 5% of the service area and 37% of such sales are in the City of Philadelphia. In 1994, approximately 60% of the Company's electric output was generated from nuclear sources. The Company estimates for 1995 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 1994, 89.7% of the Company's operating revenues and 94.0% of its operating income were from electric operations. Electric sales and operating revenues for 1994 by classes of customers are set forth below:
In 1994, 97.8% of the Company's service territory operating revenues were from Company sales in Pennsylvania and 2.2% were from sales by the Company's wholly owned subsidiary Conowingo Power Company (COPCO) in Maryland. On May 24, 1994, the Company entered into a stock purchase agreement to sell COPCO to Delmarva Power & Light Company (Delmarva). Under the terms of the stock purchase agreement, Delmarva will pay $150 million for COPCO. The sale is subject to state and federal regulatory approvals. Recognition of the gain on the sale, which the Company expects to be approximately $40 million after taxes, is contingent upon the completion of the sale. The COPCO sale does not involve the Conowingo Project which is owned by other subsidiaries of the Company.
Due to rerates and the results of the Company's last electric base rate case, the Company currently has 989 megawatts (MW) of excess installed generating capacity, which is available for off-system sales, and expects to have 1,201 MW of excess installed generating capacity by 1997. For 1994, sales to other utilities consisted of negotiated agreements to sell energy associated with up to 989 MW of near-term excess capacity. See "Rate Matters." These agreements are primarily for ongoing, short-duration purchases of energy. The Company expects to sell approximately $125 million of energy and/or capacity through such agreements in 1995. The Company also expects to purchase power from other companies in 1995 for its own use and for resale depending upon the business opportunity.
In May 1994, the Company entered into a ten-year contract to sell capacity and energy to Delmarva as part of the Company's agreement to sell COPCO to Delmarva. Revenue received under this contract is expected to offset the revenue lost as a result of the sale of COPCO. This contract is subject to state and federal regulatory approvals and the sale of COPCO to Delmarva.
In 1994, the Company also finalized an agreement to sell 140 MW of energy and capacity to Baltimore Gas and Electric Company (BG&E) for a 25-year term beginning in 1997, subject to state and federal regulatory approvals. The sale is expected to generate approximately $45 million in revenue annually. On November 17, 1994, the Company submitted the BG&E agreement to the FERC. On December 13, 1994, Duquesne Power & Light Company (Duquesne) filed with the FERC a motion to intervene and protest in the FERC proceeding. The proceeding awaits FERC action.
The net installed electric generating capacity (summer rating) of the Company and its subsidiaries at December 31, 1994 was as follows:
The maximum hourly demand on the Company's system was 7,227 MW which occurred on July 8, 1994. The Company estimates its generating reserve margin for 1995 to be 29%. 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.
The Company is a member of the Pennsylvania-New Jersey-Maryland Interconnection Association (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 45,992 MW occurred on July 8, 1994 when PJM's installed capacity (summer rating) was 56,073 MW. The Company's installed capacity for 1995-98 is expected to be sufficient for the Company to meet its obligation as a member of PJM to supply its PJM reserve margin share during that period.
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 Unit No. 1 has a capacity of 1,055 MW; Limerick Unit No. 2 has a capacity of 1,115 MW; Peach Bottom Unit No. 2 has a capacity of 1,093 MW, of which the Company is entitled to 464 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 have a capacity of 1,106 MW each, 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 $8.9 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 $8.9 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, following an accident, the facility is in a safe and stable condition and can be maintained in such condition. Within 30 days of stabilizing 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 permit either 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 will 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 have been 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 the timing of the availability of insurance proceeds 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 $44 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 or results of operations.
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 21-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 $14 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 used to decommission such nuclear facilities. The Company's ownership portion of decommissioning costs is approximately $643 million, expressed in 1990 dollars. Under current rates, the Company collects approximately $20 million annually from customers for decommissioning the Company's nuclear units. At December 31, 1994, the Company held $174 million in trust accounts, representing amounts recovered from customers and realized investment earnings thereon, to fund future decommissioning costs. The most recent estimate of the Company's share of the cost to decommission its nuclear units is approximately $900 million in 1994 dollars. The Company would ultimately seek to recover through the ratemaking process the increase in the 1990 decommissioning cost estimate being recovered in base rates, although such recovery is not assured. For additional information concerning nuclear decommissioning, see note 3 of Notes to Consolidated Financial Statements included in the Company's Annual Report to Shareholders for the year 1994.
Limerick Generating Station
Limerick Unit No. 1 achieved a capacity factor of 85% in 1994 and 95% in 1993. Limerick Unit No. 2 achieved a capacity factor of 93% in 1994 and 81% in 1993. 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 1995, 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 throughout the SALP period. The Company has taken and is taking actions to address the weaknesses discussed in the SALP Report. The next SALP Report for Limerick, for the period September 26, 1993 to April 1, 1995, is expected to be received during the second quarter of 1995.
In October 1990, General Electric Company (GE) reported that crack indications were discovered near the seam welds of the core shroud assembly in a GE Boiling Water Reactor (BWR) located outside the United States. As a result, GE issued a letter requesting that the owners of GE BWRs take interim corrective actions, including a review of fabrication records and visual examinations of accessible areas of the core shroud seam welds. Peach Bottom Unit No. 3 was examined in October 1993 during its last refueling outage and crack indications were identified at two locations. On November 3, 1993, the Company presented its findings to the NRC and provided justification for continued operation of Unit No. 3 for another two-year cycle with the crack indications. Peach Bottom Unit No. 2 was examined in October 1994 during its last refueling outage and the inspection revealed a minimal number of flaws. In a letter dated November 7, 1994, the Company submitted its findings to the NRC and provided justification for continued operation of Unit No. 2. Initial examinations for Limerick Units No. 1 and No. 2 have been scheduled for the refueling outages planned for January 1996 and January 1999, respectively, in accordance with industry experience and guidance. The Company is participating in a GE BWR Owners Group to develop long-term corrective actions.
On July 24, 1992, the NRC issued an information notice alerting utilities owning 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, Limerick Unit No. 1 in September 1993 and Limerick Unit No. 2 in February 1995.
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 corrective 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 fire barrier issues. The Company responded by providing details on its Thermo-Lag reduction program. By letter dated December 20, 1994, the NRC requested additional information. A response to the third letter will be provided in March 1995. The Company will complete its engineering re-analysis in 1995 for both Peach Bottom and Limerick. This re-analysis will determine the extent of modifications that will be performed over the next several years at both plants in order to complete the long-term measures to address the concern over Thermo-Lag use.
By letter dated December 9, 1992, the Company submitted a request to the NRC to rerate the authorized maximum reactor-core power levels of each Limerick unit by 5% to 1,115 MW. By letter dated February 16, 1995, the NRC approved the Company's request. The amendment for the Unit No. 2 facility operating license was effective upon the date of the NRC approval letter. The amendment of the Unit No. 1 facility operating license will be issued on December 26, 1995. Modifications to Unit No. 2 were completed during the Unit's most recent refueling outage. Modifications to Unit No. 1 are scheduled for the refueling outage planned for January 1996 .
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 at the Point Pleasant Pumping Station, transports it to the Bradshaw Reservoir (Point Pleasant Project), then to the east and main branches of the Perkiomen Creek and finally to Limerick. The supplemental cooling water system also provides water for public use to two Montgomery County water authorities. The Company has obtained all permits for
the construction and operation of the supplemental cooling water system. Certain of the permits relating to the operation of the system must be renewed periodically.
Although permits for the construction and operation of the supplemental cooling water system have been obtained, certain permits had been appealed. All of the appeals relating to the Point Pleasant Project have been resolved, except for two appeals pending before the Commonwealth Court of Pennsylvania (Commonwealth Court). The appeals relate to two orders issued by the Pennsylvania Environmental Hearing Board which had dismissed two appeals filed by certain environmental groups concerning National Pollutant Discharge Elimination System (NPDES) permits issued by the PDER.
Opposition to the Point Pleasant Project from various groups, including Bucks County and the Neshaminy Water Resources Authority, a municipal authority created by Bucks County which had contracted to construct the Point Pleasant Project, resulted in protracted litigation. On February 15, 1995, the Montgomery County water authorities acquired all of Bucks County's interest in the Point Pleasant Project, including an assignment of the contract pursuant to which supplemental cooling water is supplied to Limerick, resolving the litigation.
The Company had also entered into an agreement 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. Although backup sources of water have not been used recently, the Company is negotiating with the municipality to replace the agreement which expired on December 31, 1994.
Peach Bottom Atomic Power Station
Peach Bottom Unit No. 2 achieved a capacity factor of 81% in 1994 and 84% in 1993. Peach Bottom Unit No. 3 achieved a capacity factor of 98% in 1994 and 70% in 1993. 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 1994 and 1993, respectively.
By letter dated November 21, 1994, the NRC imposed a civil penalty of $87,500 on the Company. The NRC found that, on August 3, 1994, an emergency service water valve at Peach Bottom was left closed and unattended for approximately 50 minutes during valve testing, which could have impacted the ability of safety-related equipment to receive the proper cooling flow in an emergency. The NRC has recognized that the Company has subsequently taken corrective actions to prevent recurrence of the incident. By letter dated December 21, 1994, the Company paid the penalty.
On June 29, 1994, the NRC issued its periodic SALP Report for Peach Bottom for the period November 1, 1992 to April 30, 1994. The SALP Report was issued under the revised SALP process in which the number of assessment areas has been reduced from seven to four. Peach Bottom received a rating of "1" in the area of Operations. The areas of Engineering, Maintenance, and Plant Support received ratings of "2." Overall, the NRC found continued improvement in performance during the period. The NRC stated that enhancement in problem identification and resolution, good control of refuelings and outages, and excellent oversight by plant management of day-to-day activities in a manner that ensured safer operation of the units contributed to the improvement. Despite the overall improvement, the NRC noted that some areas require continued management attention and that management needs to continue to encourage plant personnel at all levels to identify existing, and sometimes longstanding, problems so that priorities can be established and effective corrective actions implemented. The NRC also noted instances of personnel inattention to detail and failure to follow procedures which warranted additional management attention. The Company has taken and is taking actions to address the weaknesses discussed in the SALP Report.
By letter dated March 28, 1994, the NRC approved the Company's request to amend the 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 previous operating licenses would have expired 40 years
from the dates of issuance of the construction permits for the Units. The amended operating license for Unit No. 2 is extended approximately five years, six months and the amended operating license for Unit No. 3 is extended approximately six years, five months.
By letter dated October 18, 1994, the NRC approved the Company's request to rerate the authorized maximum reactor-core power levels of each Peach Bottom unit by 5% to 1,093 MW. The amendment of the Unit No. 2 facility operating license was effective upon the date of the NRC approval letter. The amendment of the Unit No. 3 facility operating license will be effective upon completion of the implementation of associated hardware changes, which are to be completed during Unit No. 3's next refueling outage scheduled for the fall of 1995.
In addition to the matters discussed above, see "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 59% in 1994 and 60% in 1993. Salem Unit No. 2 achieved a capacity factor of 58% in 1994 and 57% in 1993. 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 and 1994, respectively.
The Company has been informed by PSE&G that as a result of the NRC investigation following the reactor shutdown of Salem Unit No. 1 in April 1994, PSE&G was fined $500,000 for violations relating to the failure to identify and correct significant conditions adverse to quality at the facility related to spurious steam-flow signals and inoperable atmospheric relief valves, both of which, the NRC concluded, led to unnecessary safety injections during the event; the failure to identify and correct significant conditions adverse to quality at the facility related to providing adequate training, guidance and procedures for the operators to cope with the event; and the failure by supervisors to exercise appropriate command and control of the operations staff and the reactor during the event. On November 1, 1994, PSE&G responded to the violations and paid the fine.
The Company has been informed by PSE&G that on January 3, 1995, the NRC issued its periodic SALP Report for Salem for the period June 20, 1993 to November 5, 1994. The SALP Report was issued under the revised SALP process in which the number of assessment areas has been reduced from seven to four. Salem received a rating of "3" in the areas of Operations and Maintenance, a rating of "2" in the area of Engineering, and a rating of "1" in the area of Plant Support. The NRC noted an overall decline in performance and evidenced particular concern with plant and operator challenges caused by repetitive equipment problems and personnel errors. The NRC also noted that although PSE&G has initiated several comprehensive actions within the past year to improve plant performance, and some recent incremental gains have been made, these efforts have yet to noticeably change overall performance at Salem.
The Company has been informed by PSE&G that PSE&G's own assessments, as well as those by the NRC and the Institute of Nuclear Power Operations, indicate that additional efforts are required to further improve operating performance, and PSE&G is committed to taking the necessary actions to address Salem's performance needs. It is anticipated that the NRC will maintain a close watch on Salem's performance and corrective actions related to the April reactor shutdown. No assurance can be given as to what, if any, further or additional actions may be taken or required by the NRC to improve Salem's performance.
The Company has been informed by PSE&G that PSE&G is taking significant steps to address performance shortfalls at Salem. In 1993, a comprehensive performance assessment team identified areas of weakness through an in-depth investigation of common causes and events. Corrective action plans and effectiveness measures were then initiated in 1994 and are ongoing, along with additional measures designed to achieve a change in Salem's performance. Personnel performance is being addressed through improved supervisory training, increased monitoring of work activities, improved operational command and control and the reorganization and increased staffing at Salem. PSE&G has established a goal of safe, uneventful operation to be achieved through enhanced self-assessment and corrective action processes, resolution of long-standing equipment problems, improved
independent oversight of plant operations and improved root-cause analysis of plant problems. In furtherance of these goals, PSE&G has reorganized the operational structure of its Nuclear Department and recruited a new chief nuclear officer. In addition, PSE&G's parent company, Public Service Enterprise Group, Incorporated (Enterprise), has strengthened oversight of nuclear plant operations by establishing a standing Nuclear Committee of its Board of Directors.
The Company has been informed by PSE&G that on March 21, 1995, the Boards of Directors of Enterprise and PSE&G met with NRC representatives to discuss the need for continued improvements in equipment reliability and staff performance. PSE&G cannot predict what actions, if any, the NRC may take as a result of this meeting.
In addition to the matters discussed above, see "Environmental Regulations - Water."
Fuel
The following table shows the Company's sources of electric output for 1994 and as estimated for 1995:
The following table shows the Company's average fuel cost used to generate electricity:
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 the supply of uranium concentrates for Limerick and Peach Bottom which extend through 2002. On February 23, 1995, two companies which supply uranium concentrates to the Company filed petitions for bankruptcy under Chapter 11 of the Bankruptcy Code. The two companies supply approximately half of the Company's 1995 and 1996 requirements for uranium concentrates. In addition, one of the companies is under contract to supply approximately 25% of the Company's uranium concentrate requirements for the period 1997 to 2002. The Company has made alternative arrangements with other suppliers to satisfy its short-term requirements for uranium concentrates. For the longer-term, the Company is evaluating its requirements and potential supply sources, including the two suppliers which have filed petitions for bankruptcy. The Company does not anticipate any difficulties in obtaining its requirements for uranium concentrates. 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. PSE&G has informed the Company that it does not anticipate any difficulties in obtaining its requirements for uranium concentrates. 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:
In March 1993, the Company entered into an agreement with Long Island Power Authority and other parties, subsequently revised in September 1993, to receive at no cost slightly irradiated nuclear fuel from Shoreham Nuclear Power Station. As of June 30, 1994, the Company had accepted all of the nuclear fuel shipments. The acquisition of the fuel will result in estimated benefits to the Company's customers of $70 million over the next 15 years due to reduced fuel-purchase requirements. See note 21 of Notes to Consolidated Financial Statements included in the Company's Annual Report to Shareholders for the year 1994.
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 Company currently stores all spent nuclear fuel from its nuclear generating facilities in on-site, spent-fuel storage pools. By letter dated November 29, 1994, the NRC approved the Company's request to install new high-density, spent-fuel storage racks at Limerick, which will provide for storage capacity to 2013. 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 Peach Bottom beyond the pertinent dates, including 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 DOE 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. In June 1994, a number of utilities and state agencies, including the PUC, filed a lawsuit against the DOE seeking a determination of the DOE's legal obligation to accept fuel by 1998. 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. Legislation has been introduced in 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 ($.001) per kWh of net nuclear generation. The 1994 charge collected by the Company from its customers for spent-fuel disposal was $24 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) requires, among other things, that utilities with nuclear reactors 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 $59 million for such costs at December 31, 1994. The Company is currently recovering these costs through the Energy Cost Adjustment (ECA).
The Company is currently recovering in rates costs for nuclear decommissioning and decontamination and spent-fuel storage. 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 1995 through 1999; and a total of 6,500,000 tons for the years 2000 through 2004. At December 31, 1994, 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, 1995, the Company had contracts with two suppliers for 900,000 tons per year or approximately 64% of expected annual requirements. Both contracts expire on December 31, 1995.
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 June 1995, when current orders expire and new yearly orders begin. Purchase orders for distillate fuel oil are expected to meet the Company's needs through October 1995, when current orders expire and new yearly orders begin.
Natural Gas
The Company obtains natural gas for electric generation through a combination of short-term orders and spot purchases made on the open market, as well as through the Company's own City Gate Sales Tariff. The Company obtains the limited quantities of natural gas used by the auxiliary boilers and pollution control equipment at Eddystone through the same means. The Company has the capability to use either oil or natural gas at Cromby Unit No. 2 and Eddystone Units No. 3 and No. 4.
Gas Operations
During 1994, 10.3% of the Company's operating revenues and 6.0% of its operating income were from gas operations. Gas sales and operating revenues for 1994 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 up to five 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 transportation contracts is 87.5 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, 1994:
The following table sets forth the Company's major transmission and distribution lines in service at December 31, 1994:
At December 31, 1994, the Company's principal electric distribution system included 12,588 pole-line miles of overhead lines and 20,748 cable miles of underground cables.
The Company is in the midst of an ongoing 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, 1994:
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 21 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 15 of Notes to Consolidated Financial Statements included in the Company's Annual Report to Shareholders for the year 1994.
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 $44 million for property losses incurred at any plant insured by the insurance companies (see "ITEM 1. BUSINESS - Electric Operations - General"). 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 and results of operations.
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 1990 Early Retirement Plan, thereby depriving the plaintiffs of substantial pension and salary benefits. In June 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 1990 Early Retirement Plan, as well as punitive damages. On March 24 and 25, 1994, the case was tried in Eastern District Court on the issue of liability. On May 13, 1994, the Eastern District Court issued a decision, finding the Company liable to all plaintiffs who made inquiries about any early retirement plan after March 12, 1990 and retired prior to April 1990. The Eastern District Court will try the case on the issue of damages. 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 between January and 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 March 24 and 25, 1994, the case was tried in Eastern District Court on the issue of liability. On May 13, 1994, the Eastern District Court issued a decision, finding the Company liable to all plaintiffs who made inquiries about any pension improvement after March 1, 1987 and retired prior to June 1987. The Eastern District Court will try the case on the issue of damages. 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 was 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 would be in the best interests of the Company and its shareholders. On March 14, 1994, upon the recommendation of the special committee, the Board of Directors approved 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. The derivative suit is based on the findings and conclusions contained in the Credit and Collections 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 April 12, 1994, the Company filed a motion for summary judgment seeking termination of the action pursuant to the Board of Directors' resolution of March 14, 1994. 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, 1995, there were 196,717 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 1993 and 1994 is incorporated herein by reference to "Operating Statistics" in the Company's Annual Report to Shareholders for the year 1994.
The book value of the Company's common stock at December 31, 1994 was $19.41 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, 1994, such capital ($4.30 billion) amounted to about 12 times the liquidating value of the outstanding preferred stock ($370.2 million).
The Company may not declare dividends on any shares of its capital stock in the event that: (1) the Company exercises its right to extend the interest payment periods on the Company's 9% Deferrable Interest Subordinated Debentures, Series A (Subordinated Debentures), which were issued to PECO Energy Capital, L.P.; (2) the Company defaults on its guarantee of the payment of distributions on the Cumulative Monthly Income Preferred Securities of PECO Energy Capital, L.P.; or (3) an event of default occurs under the Indenture under which the Subordinated Debentures are issued.
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 1994.
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 1994.
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 1994.
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 1995 Annual Meeting of Shareholders to be held April 12, 1995, 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 1995 Annual Meeting of Shareholders to be held April 12, 1995, under the heading "Executive Compensation Disclosure" 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 1995 Annual Meeting of Shareholders to be held April 12, 1995, 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 1995 Annual Meeting of Shareholders to be held April 12, 1995, 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 Schedule
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 1994 and incorporated by reference into this Form 10-K Annual Report, the Annual Report to Shareholders for the year 1994 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 1994 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 schedule listed in the index in Item 14 of this Form 10-K.
In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
COOPERS & LYBRAND, L.L.P.
2400 Eleven Penn Center Philadelphia, Pennsylvania January 30, 1995
PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
SCHEDULE II - 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 (1993 Form 10-K, Exhibit 3-1).
3-2 Bylaws of the Company, adopted February 26, 1990 and amended January 24, 1994 (1993 Form 10-K, Exhibit 3-2).
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:
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).
4-5 Indenture, dated as of July 1, 1994, between the Company and Meridian Trust Company, as trustee.
4-6 Deferrable Interest Subordinated Debenture Certificate, Series A.
4-7 Payment and Guarantee Agreement, dated July 27, 1994, executed by the Company in favor of the holders of Cumulative Monthly Income Preferred Securities of PECO Energy Capital, L.P.
10-1 Pennsylvania-New Jersey-Maryland Interconnection Agreement dated September 26, 1956 (Registration No. 2-13340, Exhibit 13-40) and agreements supplemental thereto:
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 PECO Energy Company 1989 Long-Term Incentive Plan (Registration No. 33-30317, Exhibit 28).*
10-7 Amended and Restated Limited Partnership Agreement of PECO Energy Capital, L.P., dated July 25, 1994.
10-8 Stock Purchase Agreement between the Company and Delmarva Power & Light Company, dated May 24, 1994.
10-9 Agreement between the Company and Delmarva Power & Light Company for the purchase and sale of capacity and energy, dated May 24, 1994.
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 1994.
21 Subsidiaries of the Registrant.
23 Consent of Independent Accountants.
24 Powers of Attorney.
27 Financial Data Schedule.
--------------- * 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, 1994, the Company filed Current Reports on Form 8-K, dated:
October 7, 1994 reporting information under "ITEM 5. OTHER EVENTS" concerning the resolving of all of the issues associated with the Company's single-issue rate increase to recover the costs associated with the implementation of Statement of Financial Accounting Standards No. 106 - "Employers' Accounting for Postretirement Benefits Other Than Pensions"; and
October 13, 1994 reporting information under "ITEM 5. OTHER EVENTS" relating to the issuance of a tentative order issued by the Pennsylvania Public Utility Commission permitting recovery of a portion of the costs associated with the implementation of Statement of Financial Accounting Standards No. 106 - "Employers' Accounting for Postretirement Benefits Other Than Pensions."
Subsequent to December 31, 1994, the Company filed a Current Report on Form 8-K, dated:
February 2, 1995 reporting information under "ITEM 5. OTHER EVENTS" relating to a press release issued by the Company concerning management changes.
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 24th day of March 1995.
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.
This annual report has also been signed below by C. A. McNeill, Jr., Attorney-in-Fact, on behalf of the following Directors on the date indicated:
SUSAN W. CATHERWOOD JOSEPH C. LADD M. WALTER D'ALESSIO EDITHE J. LEVIT R. G. GILMORE KINNAIRD R. MCKEE R. H. GLANTON JOSEPH J. MCLAUGHLIN JAMES A. HAGEN JOHN M. PALMS NELSON G. HARRIS RONALD RUBIN ROBERT SUBIN
By /s/ C. A. MCNEILL, JR. March 24, 1995 C. A. McNeill, Jr., Attorney-in-Fact