Annual Report (Form 10-K), fiscal year 1994

ITEM 1 BUSINESS
General
Atlantic Energy, Inc. (the Company), the principal office of which is located at 6801 Black Horse Pike, Egg Harbor Township, New Jersey, (mailing address-6801 Black Horse Pike, Pleasantville, NJ 08232, telephone 609-645-4500) was organized under the laws of New Jersey in August 1986. The Company is a public utility holding company as defined in the Public Utility Holding Company Act of 1935 (the 1935 Act), and has claimed an exemption from substantially all of the provisions of the 1935 Act. The Company is the parent company of Atlantic City Electric Company (ACE) and several non-utility subsidiaries as follows: Atlantic Generation, Inc. (AGI), ATE Investment, Inc. (ATE), Atlantic Southern Properties, Inc. (ASP), Atlantic Energy Technology, Inc. (AET) and Atlantic Thermal Systems, Inc. (ATS). On January 1, 1995, the Company formed a new subsidiary, Atlantic Energy Enterprises, Inc. (AEE), to which ownership of the existing non-utility companies will be transferred.
Principal cash inflows of the Company include proceeds from the issuance and sale of its Common Stock and the receipt of dividends from ACE. During 1994, the Company's Dividend Reinvestment and Stock Purchase Plan, before converting to an open market type plan, raised $14 million in new equity capital and issued 699,493 new shares of Common Stock. Proceeds from the issuance and sale of Common Stock by the Company are deposited into the general funds of the Company and are invested in ACE and other subsidiaries based upon their respective capital requirements. Principal cash outflows of the Company in 1994 included capital contributions and advances to its subsidiaries, the payment of dividends to common shareholders and the repurchase of outstanding common stock.
Atlantic City Electric Company
ACE, which has a wholly-owned subsidiary, Deepwater Operating Company, is the principal subsidiary of the Company and is engaged in the generation, transmission, distribution, and sale of electric energy in the southern part of New Jersey. ACE's principal office is located at 6801 Black Horse Pike, Egg Harbor Township, New Jersey (mailing address-6801 Black Horse Pike, P.O. Box 1264, Pleasantville, NJ 08232, telephone 609-645- 4100), and was organized under the laws of New Jersey on April 28, 1924, by merger and consolidation of several utility companies. ACE is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). At December 31, 1994, ACE had over 465,000 customers and employed 1,794 persons, of which 741 were affiliated with a national labor organization. With the exception of a municipal electric system providing electric service within the municipal boundaries of the City of Vineland, New Jersey, ACE supplies electric service to the southern one- third of the State of New Jersey.
ACE is a utility whose peak load has occurred during the summer months, and approximately 30% of 1994 revenues were recorded during the quarter ended September 30, 1994.
ACE has experienced, in varying degrees, some of the problems common to the electric utility industry in general, particularly an increasingly competitive energy marketplace. In addition, certain problems experienced by other utilities could have an indirect effect upon ACE's operations and financial condition, as a result of common regulatory requirements and the fact that general industry developments could affect ACE's cost of capital.
Competition
Between 1991 and 1994, sales to industrial customers declined as a result of cogeneration projects constructed pursuant to the Federal Public Utility Regulatory Policies Act (PURPA). Effective June 30, 1994, a contract with ACE's largest industrial customer was terminated. ACE's contract provided for the delivery of process steam, water and by-product electricity generated by back pressure turbines by a subsidiary of ACE. In 1993, ACE received $12 million in revenues for services and energy sales. In accordance with the termination agreement, ACE received $4.2 million in cash proceeds, certain emission allowances valued at $6.5 million and made provisions to retire certain equipment. The steam and electricity needs of this customer are now provided by a non-utility cogeneration facility. In addition, ACE has a contract for the purchase of 188 megawatts (MW) of capacity and energy from this facility.
Currently, ACE is under contract with four independent power producers for the purchase of 572 MW of capacity and energy including the facility above. The effects of any such future displacement from cogeneration projects could be mitigated by natural growth in the service territory and additional marketing efforts by ACE to reduce the impact of the potential loss of kilowatt-hour sales and revenues.
As a result of changes in Federal law designed to promote energy efficiency, reduce reliance on imported oil, and encourage competition in the generation of electricity, the electric utility business is undergoing significant changes. In October 1992, the Energy Policy Act (the Act) was enacted which includes, among other things, amendments to the Public Utility Holding Company Act of 1935 (PUHCA) and PURPA. The Act provides for increased competition between utility and non-utility electric generators, and provides for the creation of exempt wholesale generators which would be exempt from certain PUHCA regulation. The Act also permits FERC to authorize wholesale transmission access, or wheeling, provided that certain requirements are met. On October 26, 1994, FERC issued a pricing policy statement which became effective upon issue. The policy statement is designed to provide the framework for developing transmission pricing tariffs and contains several principles for evaluation of proposals. Proposals include those based on a standard methodology which seeks to recover costs based on traditional revenue requirements, or embedded cost, and those based on non-traditional approaches that deviate from the utility's embedded cost. Filing for an open access transmission tariff with the FERC may not be required until such time as a transmission service agreement needs to be filed for a specific customer.
Another factor in determining the effects of competition on the electric utility business will be the extent to which New Jersey public utility regulation is modified to reflect the competitive energy marketplace. In that regard, the Draft New Jersey Energy Master Plan Phase I Report was issued in November 1994 and is designed to provide a framework for managing the transition of the State's natural gas and electric power industries from markets guided by regulation to those guided by market-based principles and competition. For further information see "Capacity Planning" herein.
Legislation proposed for New Jersey would, if enacted, allow the BPU, upon petition from any electric or gas utility, to adopt a plan of regulation other than the traditional rate base/rate of return regulation. The legislation is designed to promote economic development and will include investment in, or expenditures for, innovative programs or technology for energy conservation, energy efficiency or environmental quality. The BPU, during the planning of the New Jersey Energy Master Plan, has indicated that a new bill is to be drafted and introduced for legislative approval.
Other proposed regulatory changes have been suggested relating to matters at the state and Federal level which could have operating and financial implications for ACE. See "Competition", "Regulation" and "Environmental Controls" herein for additional information.
Nonutility Subsidiaries
Atlantic Generation, Inc.
At December 31,1994, AGI's activities were represented by partnership interests in three cogeneration power projects.
Project Fuel Capacity Commercial Ownership Location Type (MW) Operation Interest
Binghamton, New York gas 50 1992 one-third Pedricktown, New Jersey gas 117 1992 one-half Vineland, New Jersey gas 46.5 1994 one-half
Subsidiaries of Tristar Ventures Corporation (Tristar), a subsidiary of The Columbia Gas System, Inc. (Columbia) have partnership interests in both the Pedricktown and the Binghamton projects; subsidiaries of Stone & Webster Development Corporation have a one-third partnership interest in the Binghamton project. The Binghamton facility is hosted by a large paper manufacturer and supplies New York State Gas and Electric under a power purchase agreement. The Pedricktown facility is hosted by a tire manufacturer and supplies 106 MW of capacity and energy to ACE under a cogeneration agreement executed by ACE and approved by the BPU. An amendment to this agreement, which returns the project host to ACE as a retail customer has been completed, executed and is awaiting BPU approval. The Vineland facility is hosted by a food processor and provides 46.5 MW of capacity and energy to the City of Vineland under a twenty-five year contract.
During 1994, AGI and its partner in Cogeneration Partners of America, TriStar, split the day-to-day responsibilities related to their cogeneration projects. AGI maintained management of plant operations while TriStar maintained responsibility for the financial, legal and fuel procurement matters. Columbia, Tristar's parent company, and its principal subsidiary, Columbia Gas Transmission Corporation, filed petitions seeking protection under Chapter 11 of the Federal Bankruptcy Code in July 1991. A reorganization plan from both companies is expected to be filed during the first half of 1995. AGI does not anticipate any changes in its common partnership arrangements as a result of the reorganization plan.
At December 31, 1994, total equity in AGI amounted to $23.6 million, the funding of which has been through capital contributions and advances from the Company.
ATE Investment Inc.
ATE commenced activities in 1988. At December 31, 1994, ATE has invested $78.2 million in leveraged leases of three commercial aircraft and two containerships. ATE has issued $15 million principal amount of long term debt and has utilized a revolving credit and term loan agreement with a bank to finance a portion of its investment in leveraged leases and other investment activities. The remainder is provided by capital contributions from the Company. At December 31, 1994, total equity amounted to $9.4 million.
Atlantic Southern Properties, Inc.
ASP owns and manages a 280,000 square foot commercial property within the Company's service territory. A portion of the office space is presently under lease to ACE. At December 31, 1994, ASP's assets consisted primarily of this real estate site at a net book value of $10.3 million. Financing ASP's operations have been accomplished through capital contributions and advances from the Company, and loans from ATE. At December 31, 1994, equity totalled $3.2 million.
Atlantic Energy Technology, Inc.
AET's sole investment is a 100% ownership interest in a company that owns a patented technology and has proprietary knowledge relating to alternate energy technologies. Previous funding of this investment has been through capital contribution and loans from the parent company. AET has ceased operations and is currently concluding the affairs of its subsidiary. As of December 31, 1994, equity in AET totalled $1.3 million.
Atlantic Thermal Systems, Inc.
In May 1994, the Company formed a subsidiary, Atlantic Thermal Systems, Inc., to develop, own and operate thermal heating and cooling systems. ATS, and its wholly-owned subsidiary also formed in May 1994, has obtained funds for its project development through advances from the Company and through loan agreements with ATE. At December 31, 1994, advances from the Company amounted to $3.6 million and equity contributions by AEI amounted to $2.6 million.
Atlantic Energy Enterprises, Inc.
On January 1, 1995, the Company formed a new subsidiary, Atlantic Energy Enterprises, Inc., a holding company, to which ownership of the existing non-utility businesses were transferred. Under this organizational structure, AEE expects to pursue non-regulated business opportunities related to the core utility business with greater flexibility. AEE's business plan projects an investment of approximately $215 million over the next five years.
The amount of capital invested by the Company in its non- utility subsidiaries will be affected, to a large degree, by the rate of development of the respective businesses, by the business opportunities which may exist and by the opportunities for external financings by such subsidiaries themselves.
Construction and Financing
ACE maintains a continuous construction program, principally for electric generation, transmission and distribution facilities. The construction program, including the estimates of construction expenditures, as well as the timing of construction additions, is under continuous review. ACE's construction expenditures will depend upon factors such as long term load growth, general economic conditions, the ability of ACE to raise the necessary capital, regulatory and environmental requirements, the availability of capacity and energy from utility and nonutility sources and the Company return on such investments. Reference is made to "Energy Requirements and Power Supply" herein for information with respect to ACE's estimates of future load growth and capacity plans.
ACE's construction program and related expenditures reflect the anticipated effects of customer-owned generation, cogeneration and ACE's demand-side management programs. ACE's demand-side management programs are designed to reduce the rate of growth in electric system peak demand without restricting the continued economic development of ACE's service area. ACE anticipates that its demand-side management programs will encourage the efficient use, and shift the pattern, of energy consumption, resulting in a deferral of future construction. Although deferrals in construction timing may result in near-term expenditure reductions, changes in capacity plans and general inflationary price trends could increase ultimate construction costs.
The table below presents ACE's estimated cash construction costs for utility plant for the years 1995 through 1997:
(Millions of Dollars) 1995 1996 1997 Total Nuclear Generating $ 14 $ 12 $ 7 $ 33 Fossil Steam Generating 23 7 7 37 Transmission and Distribution 56 42 35 133 General Plant 19 17 15 51 Combustion Turbine 4 3 7 14 Total Cash $116 $ 81 $ 71 $268 Construction Costs ==== ==== ===== ====
On an interim basis, ACE finances that portion of its construction costs and other capital requirements in excess of its internally generated funds through the issuance of unsecured short term debt, consisting of bank loans and commercial paper. ACE undertakes permanent financing through the issuance of long term debt, preferred stock and/or capital contributions from the Company. Costs associated with ACE's share of nuclear fuel requirements for the jointly-owned Peach Bottom, Salem and Hope Creek generating stations have been financed by a non-affiliated company which generally recovers its investment costs as nuclear fuel is consumed for power generation.
At December 31, 1994, ACE had available for use various bank lines of credit totaling $150 million, which are subject to continuing review and to termination by the banks involved. On December 31, 1994, ACE had short term borrowings of $8.6 million outstanding. Based on the above level of construction expenditures, ACE currently estimates that during the three-year period 1995-1997, it will issue, excluding amounts issued for refunding purposes, approximately $50 million in debt, including First Mortgage Bonds. ACE also undertakes to reduce its overall cost of funds through refundings of existing securities. During 1994, ACE refunded and retired over $41.56 million principal amount of its First Mortgage Bonds, plus premiums. Funds for such redemptions were obtained through the issuance and sale by ACE of $54.65 million of First Mortgage Bonds. Additional funds were used for construction purposes. Reference is made to "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Notes 6 and 7 of the Notes to Financial Statements, incorporated by reference herein as Exhibit 28(a), for information relating to ACE's financing activities for the 1992-1994 period and for maturities and sinking fund provisions during the period 1995-1997.
ACE's debt securities are currently rated "A-/A3" by the major rating agencies, its preferred stock is rated "BBB+/Baa1" and its commercial paper is rated "A-2/P2."
No assurances can be given that the ratings of ACE's securities will be maintained or continue at their present levels, or be withdrawn if such credit rating agency should, in its opinion, take such action. Downward revisions or changes in ratings of a company's securities could have an adverse effect on the market price of such securities and could increase a company's cost of capital.
Rates
ACE's rates for electric service at retail are subject to the approval of the BPU. For information concerning changes in base rates and the levelized energy clause (LEC) for the years 1992 through 1994 and certain other proceedings relating to rates, see "Purchased Power" herein and Notes 1, 3 and 8 of ACE's Notes to Financial Statements, incorporated by reference herein as Exhibit 28(a).
A performance standard for ACE's five jointly-owned nuclear units was adopted in 1987 by the BPU, with certain aspects of the performance standards revised effective January 1, 1990. Under these standards, the target capacity factor for such units remained at 70%, but are measured based upon the maximum dependable capacity of the units. The zone of reasonable performance (deadband) is between 65% and 75%. Penalties or rewards are based on graduated percentages of estimated costs of replacement power. Such amount is calculated monthly, utilizing the average PJM monthly billing rate as the cost basis for replacement power, to the boundaries of the deadband, with penalties calculated incrementally in steps. Any penalties incurred are not permitted to be recovered from customers and are required to be charged against income. Implementation of the nuclear unit performance standard is done through ACE's LEC for which rates are generally set annually.
The 1994 composite capacity factor for ACE's jointly-owned nuclear units was 73.2%, which did not result in a penalty or reward under the nuclear performance standard. (See "Nuclear Generating Station Developments" herein.)
In February 1995, ACE filed a petition with the BPU requesting approval of a pilot economic development power contract program for large commercial and industrial customers. This pilot program, if approved, would permit industrial and commercial customers to contract for electric service on a negotiated basis with ACE, and is designed to promote economic stability and job retention and creation. Contracts of between three and seven years would be available to those customers who maintain or increase load by at least 500 kilowatts (KW) or new customers with load of at least 2,000 KW. Contract pricing would be, at a minimum, the marginal cost of service and, at a maximum, the current tariff rate. The pilot would be limited to an aggregate of 125 megawatts, or approximately 7% of ACE's utility system peak. The timing of BPU approval on this proposal is not known at this time.
Energy Requirements and Power Supply
ACE's 1994 kilowatt-hour sales increased by approximately 1.3% over 1993 sales. Commercial sales grew by 2.6%, offset by a 2.9% decline in industrial sales. The 1994 utility system's peak demand of 1,834 MW occurred on July 9, 1994, below the record peak demand recorded on Saturday, July 10, 1993 at 1,962 MW.
For the five-year period of 1995 through 1999, ACE's estimate of projected annual sales growth is 2.4% and peak load growth (adjusted for weather) is 2.0%. These include the estimated effects of load-reducing cogeneration and demand-side management programs.
ACE has generally been able to provide for the growth of energy requirements through the construction of additional generating capacity, joint ownership in larger units and through capacity purchases from other utilities. The net summer installed capacity, in KW, of ACE at December 31, 1994, consisted of the following: Year(s) Net Station and Primary Unit(s) Capability Location Fuels Installed (KW)
Deepwater Salem Co., N.J. Oil/Coal/Gas 1930/ 54,000 1954-1958 166,000 B.L. England Cape May Co., N.J. Coal/Oil 1962-1964/ 289,000 1974 155,000 Keystone Indiana Co., PA. Coal 1967-1968 42,000 (1) Conemaugh Indiana Co., PA. Coal 1970-1971 65,000 (1) Peach Bottom York Co., PA. Nuclear 1974 157,000 (1) Salem Salem Co., N.J. Nuclear 1977-1981 164,000 (1) Hope Creek Salem Co., N.J. Nuclear 1987 52,000 (1) Combustion Turbine Units Oil/Gas 1967-1991 524,000 (various locations)
Diesel Units Oil Total Generating Capability 1961-1970 8,700
Firm Capacity Purchases and Sales-Net 651,000 (2) Total Capability 2,327,700 ==========
Notes (1) ACE's share of jointly-owned stations. See Note 5 of ACE's Notes to Financial Statements, incorporated by reference herein as Exhibit 28(a). (2) 125,000 KW from thirteen coal-fired units of Pennsylvania Power & Light Company, 572,000 KW from four nonutility suppliers, and the sale of 46,000 KW to another electric utility.
Certain of ACE's units at the Deepwater and B. L. England Stations and certain combustion turbine units have the capability of using more than one primary fuel type. In such instances, the use of a particular fuel type depends upon relative cost, availability and applicable environmental regulations and requirements.
Power Pool and Interconnection Agreements
ACE is a member of PJM, an integrated power pool which coordinates the bulk power supply to eleven member utilities in Pennsylvania, New Jersey, Delaware, Maryland, Virginia and the District of Columbia, and is interconnected with other major utilities in the northeastern United States. As a member of PJM, ACE is required to plan for reserve capacity based on estimated aggregate PJM requirements allocated to member companies. ACE periodically files its capacity addition plans with PJM which are intended to meet forecast capacity and reserve obligations. PJM member companies make use of a planning year concept in reviewing capacity and reserve requirements. Each planning year commences on June 1 and ends on the succeeding May 31. PJM provides for after-the-fact accounting by its members for differences between forecast and actual load experience. ACE is also a party to the Mid-Atlantic Area Coordination Agreement, which provides for coordinated planning of generation and transmission facilities by the companies included in PJM. Further coordination of short term power supply planning is provided by inter-area agreements with adjacent power pools.
Power Purchases and Sales
Pursuant to power purchase arrangements with Pennsylvania Power and Light Company (PPL), ACE is purchasing a total of 125 MW of capacity and energy from PPL coal-fired sources through September 2000. ACE also has agreements with certain other electric utilities for the purchase of short term generating capacity, energy and transmission capacity on an as-needed basis, which are utilized to the extent they are economic and available.
ACE has agreed to sell 46 MW of firm capacity to Baltimore Gas & Electric Co. for the period June 1, 1994 through May 31, 1995 and 34 MW for the period June 1, 1995 through May 31, 1996.
Capacity Planning
New capacity built by a utility is subject to a Certificate of Need (CON) process. A CON is required prior to constructing a new generating facility in excess of 100 MW, or adding either 100 MW or 25% of capacity, whichever is smaller, to an existing site. In addition, New Jersey utilities are required to comply with a stipulation of settlement approved by the BPU in July 1988. The purpose of the stipulation of settlement is to procure future capacity and energy from qualified cogeneration and small power production facilities through an annual competitive bidding process, based on a long-term capacity plan. The amount to be bid upon is subject to BPU review and will be based upon such factors as a utility's five year projected capacity needs and its current generating capacity, service life extension plans for existing units, new construction, power purchases and commitments from other utilities and non-utility sources. In general, the procedures provide that each utility will procure non-utility power when needed through an evaluation system which ranks proposed projects on price and non-price factors. The price of such power is capped at the utility's avoided cost, which avoided cost is subject to BPU review, with a floor price of 25% of such avoided cost. Non-price factors in the evaluation process include project status and viability, fuel source and efficiency, project location and environmental effects.
The stipulation of settlement was due to expire on September 15, 1993. The BPU ordered an extension of the current date filing requirements consistent with PURPA requirements through February 18, 1995. Similarly, the CON was set to expire on January 30, 1994. Since no processes were in place to replace the CON, the New Jersey Department of Environmental Protection (NJDEP) readopted the legislation and extended it through January 28, 1999. ACE, pursuant to the terms of the July 1988 stipulation, filed data with the BPU for the fifth procurement period in September 1993, indicating that it does not require additional nonutility capacity for the 1994-1998 period. Additional capacity is not required for the l999 planning year.
In 1993, an Advisory Council on Electricity Planning and Procurement was formed under BPU Commissioner Armenti to assess existing electric planning, resource procurement and regulatory review processes. Two working groups were formed to address the integrated resource planning (IRP) process and supply-side procurement issues, respectively. As a result of recommendations that came out of the Advisory Council discussions, two committees were formed at the state level for the development of an integrated resource planning process and a supply procurement process.
The primary purpose of the integrated resource planning process will be to define the split between supply-side and demand-side resources, and the type of resource (base, intermediate, or peaking). Supply-side and demand-side resources will each have their own bidding procedure to fill that resource need. The supply procurement process will address the procedures for bidding and construction of future resources.
In September 1994, the New Jersey Energy Master Plan Committee began discussions on an update of the 1991 State plan. The New Jersey Energy Master Plan will be developed in three phases: 1) a review of key policy goals and objectives, 2) implementation needs, and 3) an assessment of the findings. A completion date is targeted for year end 1995. Released in November 1994, the phase one draft report's key recommendations impacted New Jersey electric utilities. The recommendations include the adoption of flexible utility rates, a streamlining of the regulatory process and the revamping of tax policies on energy consumption. The streamlining of the regulatory process will build upon the groundwork already achieved in the IRP and competitive supply procurement and will include a repeal of the CON legislation.
ACE's ability to meet its planned capacity obligations and its projected load growth will depend upon the continued availability of currently owned and purchased generating capability, on the availability of capacity from cogeneration and other power projects to be owned by others, on ACE's own planned capacity additions and on capacity purchases from sources yet to be determined. ACE's installed capacity, planned capacity additions, and capacity purchase arrangements for 1995-1997 are expected to be sufficient to supply its share of PJM reserve requirements during that period. Increases in PJM reserve requirements, less than anticipated benefits associated with conservation and load management efforts, and delays in the construction of facilities by ACE or others could further increase ACE's need for additional generating capacity. To the extent that such capacity provided by others is not available, ACE would be required to pursue other sources of capacity, and to accelerate or expand its construction program which, in certain instances, may require additional regulatory approvals and construction expenditures which could be substantial. On an operational basis, ACE expects to be able to continue to meet the demand for electricity on its system through operation of available equipment and by power purchases. However, if periods of unusual demand should coincide with forced outages of equipment, ACE could find it necessary at times to reduce or curtail load in order to safeguard the continued operation of its system.
Nonutility Generation
Additional sources of capacity for use by ACE are made available by non-utility sources, principally cogenerators. ACE currently has four, BPU-approved power purchase agreements for the purchase of capacity and energy from non-utility sources under the standard offer methodology developed and approved by the BPU in August 1987.
Project Fuel MW Date of Location Type Provided Commercial Operation
Chester, solid Pennsylvania waste 75 September 1991 Pedricktown, New Jersey gas 106 March 1992 Carney's Point, New Jersey coal 188 March 1994 Logan Township, New Jersey coal 203 September 1994
Total 572
The Logan Township facility was placed in commercial operation under a renegotiated agreement approved by the BPU in August 1993. The renegotiated agreement reduced ACE's cost for capacity and energy. An amendment to the agreement between ACE and the sponsors of the Pedricktown facility has been completed, executed and is awaiting BPU approval. The amendment restructures ACE's payment for capacity and energy reducing the energy component of the payment. The amendment also increases the available capacity of the facility from 106 MW to 116 MW and returns the project's thermal host to ACE as a retail customer. Renegotiation of a third contract is currently underway and is expected to be completed in the third quarter of 1995.
Nuclear Generating Station Developments
ACE is a co-owner of the Hope Creek and Salem Nuclear Generating Stations, to the extent of 5% and 7.41%, respectively. The Hope Creek Unit and Salem Units 1 and 2 are located adjacent to each other in Salem County, New Jersey and are operated by Public Service Electric & Gas Company (PS). ACE is also an owner of 7.51% of Peach Bottom Units 2 and 3, which are located in York County, Pennsylvania and are operated by PECO. See Note 5 of the Notes to Financial Statements of ACE filed as Exhibit 28(a) and incorporated by reference for additional information relating to the Company's investment in jointly-owned generating stations.
In 1994, nuclear generation provided 23% of ACE's total energy requirements. The approximate capacity factors (based on maximum dependable capacity ratings) for ACE's jointly-owned units for 1993 and 1994 were as follows:
Unit 1994 1993
Salem Unit 1 59.3% 60.5% Salem Unit 2 57.8% 57.2% Peach Bottom Unit 2 80.3% 83.4% Peach Bottom Unit 3 97.8% 69.6% Hope Creek 78.9% 97.7%
ACE is collecting through rates amounts to fund its share of estimated future costs relating to the decommissioning of the five nuclear units in which it has joint ownership interests. Such estimated decommissioning costs are based on studies and forecasts including generic estimates provided by the NRC. Funding to cover the future costs of decommissioning each of the five nuclear units, as currently authorized by the BPU and provided for in rates, is $6.4 million annually. See Note 1 of ACE's Notes to Financial Statements filed as Exhibit 28(a) and incorporated by reference for additional information relating to nuclear decommissioning.
ACE has been advised that the NRC has raised concerns that the Thermo-Lag 330 fire barrier systems used to protect cables and equipment at the Peach Bottom Station may not provide the necessary level of fire protection and has requested licensees to describe short and long term measures being taken to address this concern. ACE has been advised that PECO has informed the NRC that it has taken short term compensatory actions to address the inadequacies of the Thermo-Lag barriers installed at 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 PECO's interim actions were acceptable. By letters dated December 22, 1993 and December 20, 1994, the NRC requested additional information on the Company's long-term measures to address Thermo-Lag 330 fire barrier issues. PECO responded to the first two letters by providing details on its Thermo-Lag reduction program. A response to the third letter will be provided in March 1995. PECO's engineering re-analysis will be completed in 1995. This re-analysis will determine the extent of modifications that will be performed over the next several years at Peach Bottom in order to complete the long term measures to address the concern over Thermo-Lag use.
ACE has been advised that in October 1990 General Electric Company (GE) reported that crack indications were discovered near the seam welds in 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 BWR plants take interim corrective actions, including a review of fabrication records and visual examinations of accessible areas of the core shroud seam welds. Both Peach Bottom Units 2 and 3 and Hope Creek are affected by this issue and both PECO and PS are participating in the GE BWR Owners Group to evaluate this issue and develop long-term corrective action. PECO advised ACE that Peach Bottom Unit 2 was inspected in October 1994 during its last refueling outage and the inspection revealed a minimal amount of flaws. In a letter dated Novebmer 7, 1994, PECO submitted its findings to the NRC and provided justification for continued operation of Unit 2. PECO also advised ACE that Peach Bottom Unit 3 was examined in October 1993 during the last refueling outage and crack indications were identified in two locations. ACE was advised that on November 3, 1993, PECO presented its findings to the NRC and provided justification for continued operation of Unit 3 for another 2-year cycle with the crack indications. At the Hope Creek Unit, PS advised ACE that during the spring 1994 refueling outage, PS inspected the shroud of Hope Creek in accordance with GE's recommendations and found no cracks. PS reports that minimal impact to Hope Creek is expected due to the age and materials of the Hope Creek shroud and the historical maintenance of low conductivity water chemistry. As a result, Hope Creek has been placed in the lowest susceptibility category by the BWR Owners' Group. ACE cannot predict what action will be taken with regard to the Peach Bottom Units or what long-term corrective actions, if any, will be identified.
The periodic review and evaluation of nuclear generating station licensees conducted by the NRC is known as the Systematic Assessment of Licensee Performance (SALP). Under the revised SALP process, ratings are assigned in four assessment areas, reduced from seven assessment areas: Operations, Maintenance, Engineering and Plant Support (the Plant Support area includes security, emergency preparedness, radiological controls, fire protection, chemistry and housekeeping). Ratings are assigned from "1" to "3", with "1" being the highest and "3" being the lowest.
Hope Creek Station
The NRC's most recent SALP report for Hope Creek for the period December 29, 1991 through June 19, 1993 assigned ratings of 1 in the areas of Plant Operations; Maintenance/Surveillance; Radiological Controls; Security; and Safety/Assessment/Quality Verification; a rating of 1-Declining, in the area of Emergency Preparedness and a rating of 2-Improving, in the functional category of Engineering/Technical Support.
ACE has been advised by PS that as a result of an NRC inspection in July 1991 at Hope Creek, an enforcement conference was held with the NRC on September 9, 1991 to discuss, among other things, three potential violations relating to reports PS submitted to the NRC regarding the reliability of motor operated valves at Hope Creek. Two violations with no civil penalty were issued to PS on October 10, 1991. The third potential violation was investigated by the NRC's Office of Investigators (OI). By letter dated October 20, 1993, the NRC advised PS that OI concluded such reports were incomplete and contained inaccurate information. An enforcement conference to review this matter was held on December 20, 1993 at which time PS presented its position on the issues to demonstrate that the reports were complete and accurate and that no violation had occurred. ACE cannot predict what actions, if any, the NRC may take in this matter.
PS has advised ACE that as a result of an internal allegation report, PS submitted a License Event Report to the NRC on October 14, 1994 which stated that in 1992, the Hope Creek control room was understaffed for approximately three minutes and a decision was made by those involved that the incident did not warrant initiation of NRC reporting documentation. A meeting with Region I NRC personnel was held on October 18, 1994 in which the NRC expressed a high degree of concern over the issue. The OI has since looked into the event, as well as an internal investigation by PS as to the validity of the allegation. The NRC's Senior Resident Inspector has indicated to PS that a Notice of Violation would likely be issued. A second meeting with the NRC was held on February 3, 1995, with resolution of this issue pending completion of the NRC's investigation. ACE cannot predict what other action, if any, the NRC may take in this matter.
Salem Station
ACE was advised on January 3, 1995, the NRC issued its SALP report for the Salem Station for the period covering June 20, 1993 through November 5, 1994. The Salem SALP report was issued under the revised SALP process in which the number of assessment areas has been reduced from seven to four: Operations, Maintenance, Engineering and Plant Support (the Plant Support area includes security, emergency preparedness, radiological controls, fire protection, chemistry and housekeeping). The NRC assigned ratings of "1" in the functional area of Plant Support, "2" in the area of Engineering and "3" in the areas of Operations and Maintenance. 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 has noted that although PS 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.
ACE was advised that as a result of the NRC investigation following the reactor shutdown of Salem Unit 1 in April 1994, PS 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, lead 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.
ACE has been advised by PS that PS'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 that PS 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.
ACE has been informed by PS that PS 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 and increased monitoring of work activities, improved operational command and control and the reorganization and increased staffing at Salem. PS 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, PS has reorganized the operational structure of its Nuclear Department and recruited a new chief nuclear officer. In addition, PS'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.
ACE was advised that on February 6, 1995, Enterprise and PS received a request from the NRC for a meeting of its representatives with their respective Board of Directors to discuss the need for continued improvements in equipment reliability and staff performance. The meeting is scheduled for March 21, 1995. Neither ACE, nor PS, can predict what actions, if any, the NRC may take as a result of this meeting.
ACE was advised in 1990 that the NJDEP issued a draft New Jersey Pollutant Discharge Elimination System (NJPDES) Permit to the Salem Station which required closed-cycle cooling. In response to the 1990 Draft Permit, PS submitted further written comments to the NJDEP regarding the ecological effects of station operations demonstrating that Salem was not having and would not have an adverse environmental impact and that closed-cycle cooling was an inappropriate solution. PS also developed and submitted a supplement to the permit renewal application setting forth an alternative approach that would protect aquatic life in the Delaware Estuary and provide other ecological benefits. PS proposed intake screen modifications to reduce fish loss, a study of sound deterrent systems to divert fish from the intake and a limit on intake flow. In addition, PS proposed conservation measures, including the restoration of up to 10,000 acres of degraded wetlands and the installation of fish ladders to allow fish to reach upstream spawning areas. Finally, PS proposed a comprehensive biological monitoring program to expand existing knowledge of the Delaware Estuary and to monitor station impacts. In June 1993, ACE was advised that the NJDEP issued Salem a revised draft permit which reconsidered the requirement for closed-cycle cooling and adopted the alternative measures proposed by PS with certain modifications. A final five-year permit was issued on July 20, 1994 with an effective date of September 1, 1994. The EPA, which has the authority to review the final permit issued by the NJDEP, completed its review and has not raised any objections. Certain environmental groups and other entities, including the State of Delaware, have filed requests for hearings with the NJDEP challenging the final permit. The NJDEP granted the hearing requests on certain of the issues and PS has been named as a respondent along with the NJDEP in these matters which are pending in the Office of Administrative Law of the State of New Jersey. ACE has been advised that PS is implementing the final permit. Additional permits from various agencies are required to be obtained to implement the permit. No assurances can be given as to receipt of any such additional permits. PS has advised ACE that it estimates that the cost of compliance with the final permit is approximately $100 million, of which ACE's share is 7.41% and is included in ACE's current forecast of construction expenditures.
Peach Bottom Station
On June 29, 1994, the NRC issued its SALP report for the Peach Bottom Station for the period covering November 1, 1992 through April 30, 1994. The NRC assigned ratings of "1" in the functional area of Operations, and "2" in the areas of Engineering, Plant Support and Maintenance. 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. ACE has been advised that PECO has taken and is taking actions to address the weaknesses discussed in the SALP Report.
ACE has been advised by PECO that in May 1992, PECO filed a request with the NRC to amend its Facility Operating License for Peach Bottom Units 2 and 3 to extend the expiration dates to 40 years from the date of issuance. The current operating licenses expire 40 years from the issuance of the construction permits, thereby allowing for an effective operating period of 34 years six months and 33 years seven months for Peach Bottom Units 2 and 3, respectively. Operating license extensions to the years 2013 and 2014 for Units 2 and 3, respectively, would result from the extension. ACE has been advised that by letter dated March 28, 1994, the NRC approved PECO's request to extend the license expiration dates.
ACE has been advised by letter dated October 18, 1994 the NRC approved PECO's request to rerate the authorized maximum reactor core power levels of each Peach Bottom units by 5% to 1,093 megawatts thermal. The amendment to the Peach Bottom Unit 2 facility operating license was effective upon the date of the NRC approval letter and the hardware changes required to rerate Unit 2 were implemented during the Fall 1994 refueling outage. After the initial start-up period, the unit has operated at the rerated conditions since its return to service on October 22, 1994. The amendment of the Peach Bottom Unit 3 facility operating license will be effective upon the implementation of associated hardware changes. The hardware changes required to rerate Peach Bottom Unit 3 are planned for the Fall 1995 refueling outage.
ACE has been advised that on November 21, 1994, the NRC issued an $87,500 fine to PECO for violations of NRC requirements during testing of certain motor-operated valves in the emergency service water (ESW) system at Peach Bottom in August 1994. The violations involved failure to adequately control testing activities. As a result, valves in the ESW system were placed in an inappropriate configuration, which could have rendered the system incapable of performing its function under accident conditions. ACE has been advised that PECO paid the fine in December 1994.
ACE has been advised that as a result of an inspection in October 1993, the NRC held an Enforcement Conference in December 1993 to discuss potential violations involving inappropriate protective measures taken by workers entering radiologically controlled areas. On January 19, 1994, the NRC issued a Level III violation with no associated civil penalty.
PECO has advised ACE that 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 changes were made on Peach Bottom Unit 2 and 3 in August 1993 and November 1993, respectively.
Fuel Supply
ACE's sources of electrical energy (including power purchases) for the years indicated are shown below:
Source 1994 1993 1992
Coal 29% 34% 37% Nuclear 23% 24% 22% Oil/Natural Gas 7% 5% 5% Interchange and Purchased Power 24% 28% 28% Cogeneration 17% 9% 8%
The prices of all types of fuels used by ACE for the generation of electricity are subject to various factors, such as world markets, labor unrest and actions by governmental authorities, including allocations of fuel supplies, over which ACE has no control.
Oil
Residual oil and distillate oil for ACE's wholly-owned stations are furnished under two separate contracts with a major fuel supplier. ACE has a contract for the supply of 1.0% sulfur residual oil for both Deepwater and B. L. England Stations and for distillate oil sufficient to supply ACE's combustion turbines. Both contracts expire October 31, 1997. See "Environmental Controls-Air" for information concerning the use of particular fuels at B. L. England Station.
On December 31, 1994, the oil supply at Deepwater Station was sufficient to operate Deepwater Unit 1 for 70 days, and the supply at B. L. England Station was sufficient to operate Unit 3 for 39 days.
Coal
ACE has contracted with one supplier for the purchase of 2.6% sulfur coal for B. L. England Units 1 and 2 through April 30, 1999. On December 31, 1994, the coal inventory at the B. L. England Station was sufficient to operate Units 1 and 2 for 83 days. See "Environmental Controls-Air" herein for additional information relating to B.L. England Station.
ACE has contracted with one supplier for the purchase of 1.0% sulfur coal for Deepwater Unit 6/8 through June 30, 1998. On December 31, 1994, the coal inventory at Deepwater Station was sufficient to operate Unit 6/8 for 117 days.
The Keystone and Conemaugh Stations, in which ACE has joint ownership interests of 2.47% and 3.83%, respectively, are mine- mouth generating stations located in western Pennsylvania. The owners of the Keystone Station have a contract through 2004, providing for a portion of the annual bituminous coal requirements of the Keystone Station. A combination of long and short term contracts provide for the annual bituminous coal requirements of the Conemaugh Station. To the extent that the requirements of both plants are not covered by these contracts, coal supplies are obtained from local suppliers. As of December 31, 1994, Keystone and Conemaugh had approximately a 22 day supply and a 66 day supply of coal, respectively.
Gas
ACE is currently capable of firing natural gas in six combustion turbine peaking units and in two conventional steam turbine generating units. ACE has entered into a firm electric service tariff with South Jersey Gas Company for the supply of natural gas to its units. The tariff provides for the payment of certain commodity and demand charges. Portions of the gas supply are obtained from the spot market under short term renewable gas supply and transportation contracts with various producers/suppliers and pipelines.
Nuclear Fuel
As a joint owner of the Peach Bottom, Salem and Hope Creek generating units, ACE relies upon the respective operating company for arrangements for nuclear fuel supply and management. ACE is responsible for the costs thereof to the extent of its particular ownership interest through an arrangement with a third party. Generally, the supply of fuel for nuclear generating units involves the mining and milling of uranium ore to uranium concentrate, conversion of the uranium concentrate to uranium hexafluoride, enrichment of uranium hexafluoride and fabrication of fuel assemblies. After spent fuel is removed from a nuclear reactor, it is placed in temporary storage for cooling in a spent fuel pool at the nuclear station site. Under the Nuclear Waste Policy Act of 1982 (NWPA), the Federal government has a contractual obligation for transportation and ultimate disposal of the spent fuel.
ACE has been advised by PECO, the operator of Peach Bottom, that it has contracts for uranium concentrates to fully operate Peach Bottom Units 2 and 3 through 2002. ACE has been advised that two of the companies that supply uranium concentrates to PECO filed for bankruptcy under Chapter 11 of the Bankruptcy Code on February 23, 1995. The two companies supply approximately half of PECO's 1995 and 1996 requirements for uranium concentrates. In addition, one of the companies is under contract to supply approximately 25% of PECO's uranium concentrate requirements for the period 1997 to 2002. ACE has been advised that PECO has made alternative arrangements with other suppliers to satisfy its short-term requirements for uranium concentrates. For the longer-term, PECO is evaluating its requirements and potential supply sources, including the two suppliers which have filed petitions for bankruptcy. ACE has been advised that neither PECO nor PS anticipate any difficulties in obtaining its requirements for uranium concentrates. ACE has also been advised that by PECO that its contracts for uranium concentrates will be allocated to the Peach Bottom units, and other PECO nuclear facilities in which ACE has no ownership interest, on an as-needed basis. ACE has also been advised that PECO has contracted for the following segments of the nuclear fuel supply cycle with respect to the Peach Bottom units through the following years:
Nuclear Unit Conversion Enrichment Fabrication
Peach Bottom Unit 2 1997 2008 1999 Peach Bottom Unit 3 1997 2008 1998
ACE has been advised by PS, the operating company for the Salem and Hope Creek Stations, that it has arrangements which are expected to provide sufficient uranium concentrates to meet the current projected requirements of the Salem and Hope Creek units through the year 2000 and approximately 60% of the requirements through 2002. PS has advised ACE that present contracts meet the other nuclear fuel cycle requirements for the Salem and Hope Creek units through the years indicated below:
Nuclear Unit Conversion Enrichment Fabrication
Salem Unit 1 2000 1998 2004 Salem Unit 2 2000 1998 2005 Hope Creek 2000 1998 2000
In conformity with the NWPA, PS and PECO, on behalf of the co-owners of the Salem and Hope Creek, and Peach Bottom stations, respectively, have entered into contracts with the Department of Energy (DOE) for the disposal of spent nuclear fuel from those stations. Under these contracts, the DOE is to take title to the spent fuel at the site, then transport it and provide for its permanent disposal at a cost to utilities based on nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under NWPA, the Federal government must commence the acceptance of these materials for permanent offsite storage no later than 1998, but it is possible that such storage may be delayed indefinitely. ACE has been advised that in December 1989, the DOE announced that it would not be able to open a permanent, high-level nuclear waste storage facility until 2010, at the earliest. 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 in 1998 or soon thereafter. ACE has been advised that in October 1990, the NRC determined that spent nuclear fuel generated in any reactor can be stored safely and without significant environmental impacts in reactor facility storage pools or in independent spent fuel storage installations located at reactor or away-from-reactor sites for at least 30 years beyond the licensed life for operation (which may include the term of a revised or renewed license). The DOE has stated that neither the NWPA nor its contracts imposes an unconditional obligation to accept spent fuel by 1998 and indicated that such obligation is conditional upon commencement of a temporary storage facility. It is not possible to predict when any type of Federal storage facility will become available.
PECO has advised ACE that spent fuel racks at Peach Bottom Units 2 and 3 have storage capacity until 1998 for Unit 2 and 1999 for Unit 3. Options for expansion of storage capacity at Peach Bottom beyond the pertinent dates, including rod consolidation, are being investigated.
PS has advised ACE that on-site temporary spent fuel storage capability will permit storage of spent fuel for Salem Units 1 an 2 through March 1998 and March 2002, respectively, when operational full core discharge capability requirements are considered. PS has advised ACE that it has developed an integrated strategy to meet the longer term Salem and Hope Creek spent fuel storage needs, and estimates that with reracking with maximum density racks, storage capability at Salem Units 1 and 2 would be extended through 2008 and 2012, respectively. PS has further advised ACE that the Hope Creek pool has the capacity to hold spent fuel through September 2007 considering operational full core discharge requirements.
The Energy Policy 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 are estimated to be $150 million per year for 15 years, of which ACE's share is estimated to be $8.5 million. The Act provides that these costs are to be recoverable in the same manner as other fuel costs. ACE has recorded a liability of $8.5 million and a related regulatory asset for such costs. ACE made its first payment related to this liability to the respective operating companies in September 1993. In ACE's 1993 LEC filing, the BPU approved a stipulation of settlement which included, among other things, the full LEC recovery of this and future assessments.
ACE is collecting through rates amounts to fund its share of the estimated future costs related to the decommissioning of the five nuclear units in which it has joint ownership interests. ACE's current annual funding amount, as authorized by the BPU, totals $6.4 million. This amount is based on estimates of the future cost of decommissioning each of the units, dates that decommissioning activities are expected to occur and an estimate of the return to be earned by the assets of the decommissioning fund. The present value of ACE's nuclear decommissioning obligation, based on 1987 site specific studies used by the BPU for approval in 1991 and restated in 1994 dollars, is $152.2 million. ACE will seek to adjust these estimates and the level of rates collected from customers in future BPU proceedings to reflect changes in decommissioning cost estimates and the expected return to be earned by the assets of the fund. As of December 31, 1994, the present value of such funding contributions based on current estimates for future decommissioning costs and the dates such activities are expected to occur is $111.4 million without regard for interest or fund appreciation. As of December 31, 1994, the cost and market value of the fund is $52 million, of which $36.9 million is qualified for Federal income tax purposes. Reserves for decommissioning obligations, presented as a component of accumulated depreciation, amounted to $51.1 million at December 31, 1994.
In January 1993, the BPU adopted N.J.A.C. 14:5A which was designed to provide a mechanism for periodic review of the estimated costs of decommissioning nuclear generating stations owned by New Jersey electric utilities. The purpose of this regulation is to insure that adequate funds are available to assure completion of decommissioning activities at the cessation of commercial operation. The regulation established decommissioning trust fund reporting requirements for electric utilities in order to provide the BPU with timely information for its oversight of these funds. See Note 1 and Note 8 of ACE's Notes to Financial Statements for further information relating to nuclear decommissioning funding.
Regulation
ACE is a public utility organized under the laws of New Jersey and is subject to regulation as such by the BPU, among others, which is also charged with the responsibility for energy planning and coordination within the State of New Jersey. ACE is also subject to regulation by the Pennsylvania Public Utility Commission in limited respects concerning property and operations in Pennsylvania. ACE is also subject, in certain respects, to the jurisdiction of the FERC, and ACE maintains a system of accounts in conformity with the Uniform System of Accounts prescribed for public utilities and licensees subject to the provisions of the Federal Power Act.
The construction of generating stations and the availability of generating units for commercial operation are subject to the receipt of necessary authorizations and permits from regulatory agencies and governmental bodies. Standards as to environmental suitability or operating safety are subject to change. Litigation or legislation designed to delay or prevent construction of generating facilities and to limit the use of existing facilities may adversely affect the planned installation and operation of such facilities. No assurance can be given that necessary authorizations and permits will be received or continued in effect, or that standards as to environmental suitability or operating safety will not be changed in a manner to adversely affect the Company, ACE or its operations.
Pursuant to legislation enacted in the State of New Jersey in 1983, no public utility can commence construction of certain electric facilities without having obtained a certificate of need from the appropriate state regulatory authorities. For purposes of the legislation, such electrical facilities are electric generating units at a single site having a combined capacity of 100 MW or more and electric generating units which, when added to an existing electric generating facility, would increase the installed capacity of such facility by 25% or by more than 100 MW, whichever is smaller.
Operation of nuclear generating units involves continuous close regulation by the NRC. Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements, and continuous demonstration to the NRC that plant operations meet applicable requirements. The NRC has the ultimate authority to determine whether any nuclear generating plant may operate. In addition, the Federal Emergency Management Agency has responsibility for the review, in conjunction with the NRC, of certain aspects of emergency planning relating to the operation of nuclear plants.
As a by-product of nuclear operations, nuclear generating units, including those in which ACE owns an interest, produce substantial amounts of low-level radioactive waste (LLRW). Such waste is presently accumulated on-site pending permanent storage in federally licensed disposal facilities located elsewhere. However, under provisions of the Federal Low Level Radioactive Policy Act, as amended (LLRWPA), as of July l, 1994, operating disposal sites have exercised their authority to either cease operation or deny access to LLRW generated in states which are not members of the regional compact in which they are located. ACE has been advised by PS and PECO that as of July l, 1994 LLRW generated at Salem, Hope Creek and Peach Bottom is being temporarily stored in on-site facilities pending development of permanent disposal sites in New Jersey and Pennsylvania. The LLRWPA further provides that each state must have a permanent storage facility operational by January 1, 1996. ACE has been advised that to date Pennsylvania has met such requirements by entering into a compact with West Virginia, Maryland, Delaware and the District of Columbia. To date, New Jersey has complied with the LLRWPA requirements by entering into a compact with the State of Connecticut and certifying its capability to manage, store or dispose of low-level radioactive waste requiring disposal after December 31, 1992. In June 1991, New Jersey enacted legislation providing for funding of an estimated $80 million cost of establishing a facility for disposal by 1998. Fee regulation provided for in the statute will permit the state to recover costs of such facility from waste generators. ACE has been advised that on-site waste storage will be provided until permanent storage facilities are operational or until another means of disposal is available. It is not possible to determine the outcome of this matter at this time.
In March 1983, New Jersey enacted the Public Utility Fault Determination Act which requires that the BPU make a determination of fault with regard to any past or future accident at any electric generating or transmission facility, prior to granting a request by that utility for a rate increase to cover accident-related costs in excess of $10 million. However, the law allows the affected utility to file for non-accident related rate increases during such fault determination hearings and to recover contributions to federally mandated or voluntary cost- sharing plans. The law further allows the BPU to authorize the recovery of certain fault-related repair, cleanup, power replacement or damage costs if substantiated by the evidence presented and if authorized in writing by the BPU.
Information regarding ACE's nuclear power replacement cost insurance and liability under the Federal Price-Anderson Act is incorporated herein by reference to Note 8 of ACE's Notes to Financial Statements, filed as Exhibit 28(a) to this report.
Environmental Matters
General
ACE is subject to regulation with respect to air and water quality and other environmental matters by various Federal, state and local authorities. Emissions and discharges from ACE's facilities are required to meet established criteria, and numerous permits are required to construct new facilities and to operate new and existing facilities. Additional regulations and requirements are continually being developed by various government agencies. The principal laws, regulations and agencies relating to the protection of the environment which affect ACE's operations are described below.
Construction projects and operations of ACE are affected by the National Environmental Policy Act under which all Federal agencies are required to give appropriate consideration to environmental values in major Federal actions significantly affecting the quality of the human environment.
The Federal Resource Conservation and Recovery Act of 1976 (RCRA) provides for the identification of hazardous waste and includes standards and procedures that must be followed by all persons that generate, transport, treat, store or dispose of hazardous waste. ACE has filed notifications and plans with the United States Environmental Protection Agency (EPA) relating to the generation and treatment of hazardous waste at certain of its facilities and generating stations.
The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), as amended by the Superfund Amendments and Reauthorization Act of 1986 (SARA), and RCRA authorize the EPA to bring an enforcement action to compel responsible parties to take investigative and/or cleanup actions at any site that is determined to present an imminent and substantial danger to the public or to the environment because of an actual or threatened release of one or more hazardous substances. The New Jersey Spill Compensation and Control Act (Spill Act) provides similar authority to the NJDEP. Because of the nature of ACE's business, including the production of electricity, various by-products and substances are produced and/or handled which are classified as hazardous under the above laws. ACE generally provides for the disposal and/or processing of such substances through licensed independent contractors. However, the statutory provisions may impose joint and several responsibility without regard to fault on the generators of hazardous substances for certain investigative and/or cleanup costs at the site where these substances were disposed and/or processed. Generally, actions directed at funding such site investigations and/or cleanups include all known allegedly responsible parties.
ACE has received requests for information under CERCLA with respect to certain sites. One site, a sanitary landfill comprising approximately 40 acres, is situated in Atlantic County, New Jersey. ACE received a Directive, dated November 7, 1991, from the NJDEP, identifying ACE as one of a number of parties allegedly responsible for the placement of certain hazardous substances, namely, flyash which had been approved as landfill material. An Administrative Consent Order (ACO) has been executed and submitted to the NJDEP by ACE and at least four other identified responsible parties. Site remediation will include a soil cover of the site. ACE has joined with three other parties and will cooperate in implementing the terms of the ACO. Approximately eight additional responsible parties have also been identified by the NJDEP. ACE, together with the other signatories to the ACO, will pursue recovery against those persons who may also pursue recovery against other responsible parties not named in the NJDEP Directive.
ACE has been served a Summons and Complaint dated June 30, 1992 in a civil action brought pursuant to Section 107(a) of CERCLA on behalf of the EPA. ACE has been named as one of several defendants in connection with the recovery of costs incurred, and to be incurred, in response to the alleged release of hazardous substances located in Gloucester County, New Jersey. Approximately 70 separate financially solvent entities have been identified as having responsibility for remediation which is now predicted to be in excess of $175 million. Sufficient discovery has been conducted to establish that ACE's contribution to the clean-up and remediation activity will be within the lower tiers of financial participation. Notwithstanding the joint and several liability imposed by law, primary responsibility will be apportioned among others, including Federal and State agencies and private parties. It is estimated that ACE's contribution for the remediation and clean-up of both the Atlantic County and Gloucester County sites is not expected to exceed $1 million.
The New Jersey Environmental Clean-up Responsibility Act was supplemented and amended in June 1993 and became the New Jersey Industrial Site Recovery Act. The act provides, among other things, that any business having certain Standard Industrial Classification Code numbers that generates, uses, transports, manufactures, refines, treats, stores, handles or disposes of hazardous substances or hazardous wastes is subject to the requirements of the act upon the closing of operations or a transfer of ownership or operations. As a precondition to such termination or transfer of ownership or operations, the approval of the NJDEP of a negative declaration, a remedial action work plan or a remediation agreement and the establishment of the remediation funding source is required.
Various state and Federal legislation have established a comprehensive program for the disclosure of information about hazardous substances in the workplace and the community, and provided a procedure whereby workers and residents can gain access to this information. Implementing the regulations provides for extensive recordkeeping, labeling and training to be accomplished by each employer responsible for the handling of hazardous substances. ACE has implemented the requirements of this legislation to achieve substantial compliance with appropriate schedules.
ACE is also subject to the Wetlands Act of 1970, which requires applications to and permits from the NJDEP for conducting regulated activities (including construction and excavation) within the "coastal wetlands," as defined therein. Legislation enacted in 1987 by the State of New Jersey designates certain areas as fresh water wetlands and restricts development in those areas.
The New Jersey Coastal Area Facility Review Act (CAFRA) requires applications to and permits from the NJDEP for construction of certain types of facilities within the "coastal area" as defined by CAFRA. Recent changes in regulations effective July 1994 may have substantive impact and are in the process of being finalized. Although the CAFRA regulations, as initially drafted, exclude certain utilities from the most rigorous portions of the regulations, electric utilities were not excluded. At the present time, the NJDEP indicates that the final rules will exclude electric lines and substation construction and maintenance from the definition of "public development". These activities will then be excluded from regulation. ACE will continue an aggressive pursuit for the exemption; omission of the exemption could have a significant impact on service to customers in the coastal regions the extent of which has not been determined.
Public concern continues over the health effects from exposure to electric and magnetic fields (EMF). To date, there are not conclusive scientific studies to support such concerns. The New Jersey Commission on Radiation Protection is considering promulgation of regulations which would authorize the NJDEP to review all new power line projects of 100 kilovolts or more. The promulgation of such regulations may affect the design and location of ACE's existing and future electric power lines and facilities and the cost thereof. ACE's program of Prudent Field Management implements reasonable measures, at modest cost, to limit magnetic field levels in the design and location of new facilities. Such amounts as may be necessary to comply with any new EMF rules cannot be determined at this time and are not included in ACE's 1995-1997 estimated construction expenditures.
Air
The Federal Clean Air Act, as amended, requires that all states achieve specified primary ambient air quality standards (relating to public health) by December 31, 1982 unless the deadline is extended for certain pollutants for a particular state by appropriate action taken by the EPA, and also requires that states achieve secondary ambient air quality standards (relating to public welfare) under the Clean Air Act within a reasonable time. The Clean Air Act also requires the Administrator of the EPA to promulgate revised new source performance standards for sulfur dioxide, particulates and nitrogen dioxide, mandate the use of the "best technological system of continuous emission reduction" and preclude the use of low sulfur coal as a sole means of achieving compliance with sulfur regulations for new power plants. The Clean Air Act Amendments (CAAA), which provide for penalties in the event of noncompliance, further provide that State Implementation Plans (SIP) contain emission limitations and such other measures as may be necessary, as determined under regulations promulgated by the EPA, to prevent "significant deterioration" of air quality based on regional non-degradation classifications.
The NJDEP is using the New Jersey Administrative Code, Title 7, Chapter 27 (NJAC 7:27) as its SIP to achieve compliance with the national ambient air quality standards adopted by EPA under the Clean Air Act. NJAC 7:27 currently provides ambient air quality standards and emission limitations, all of which have EPA approval, for seven pollutants, including sulfur dioxide and particulates. ACE believes that all of its fossil fuel-fired generating units are, in all substantial respects, currently operating in compliance with NJAC 7:27 and the EPA approved SIP.
In November 1990, the CAAA was enacted to provide for further restrictions and limitations on sulfur dioxide and other emission sources as a means to reduce acid deposition. Phase I of the legislation mandates compliance with the sulfur dioxide reduction provisions of the legislation by January 1, 1995 by utility power plants emitting sulfur dioxide at a rate of above 2.5 pounds per million BTU. Plants utilizing certain control technologies to meet the Phase I sulfur dioxide reductions could be permitted, subject to EPA approval, to either postpone compliance until 1997 or receive an early reduction bonus allowance for reductions achieved between 1995 and 1997. Phase II of the legislation requires controls by January 1, 2000 on plants emitting sulfur dioxide at a rate above 1.2 pounds per million BTU.
ACE's wholly-owned B. L. England Units 1 and 2 and its jointly-owned Conemaugh Units 1 and 2, in which ACE has a 3.83% ownership interest, are affected by Phase I, and all of ACE's other fossil-fueled steam generating units are affected by Phase II. The Keystone Station, in which ACE has a 2.47% ownership interest, is impacted by the sulfur dioxide provisions of Title IV of the CAAA during Phase II. In addition, all of ACE's fossil-fueled steam generating units will be affected by the nitrogen oxide provisions of the CAAA. Compliance with the legislation will cause ACE to incur additional capital and/or operating costs. On April 26, 1991, the NJDEP renewed ACE's expiring Certificates to Operate Control Apparatus or Equipment (Certificates) for the three generating units at B.L. England Station for a period of five years. The Certificates constitute a concurrent five-year authorization to burn coal exceeding one percent sulfur at B.L. England Units 1 and 2. Such authorization is subject to certain conditions, including the submittal by ACE of certain permits relating to the installation of flue gas desulfurization systems (scrubbers) on B.L. England Units 1 and 2. Subject to receipt of necessary permits and approvals, and to delays beyond its control, ACE would be obligated to install and operate the scrubbers by June 30, 1995 for Unit 2 and January 31, 1997 for Unit 1. The provisions of the Certificates do not preclude NJDEP or the BPU from allowing ACE to pursue a compliance strategy other than scrubbing, or from disapproving any compliance strategy, including scrubbing. The Certificates do not preclude the NJDEP from requiring reductions in the emissions of nitrogen oxides, and require periodic reporting by ACE on nitrogen oxide control strategies, and by the end of 1995, an evaluation of the applicability of nitrogen oxide control at B.L. England Station.
ACE constructed a scrubber at a cost of approximately $81 million, at B.L. England Unit 2, which will satisfy Phase I sulfur dioxide emission requirements for both B.L. England Units 1 and 2. Construction of the scrubber commenced in late 1992 and commercial operation began in late 1994. The Conemaugh owners have elected to install scrubbers on Conemaugh Units 1 and 2, with ACE's share of the total cost estimated to be about $15 million. Scrubber construction for Conemaugh Unit 1 was also completed in late 1994 and Unit 2 construction is expected to be completed in 1995. The cost of certain power purchase arrangements between ACE and other electric utilities may also be affected by the legislation. A portion of the capital costs necessary to continue compliance with the CAAA are included in ACE's current estimate of construction expenditures shown under "Construction and Financing" above. ACE expects that costs associated with compliance would be recoverable through rates, and may be offset, in part, by utilization of certain allowances as permitted by the CAAA, the value of which is not presently determinable.
The CAAA requires that reductions in nitrogen oxide (Nox)be made from the emissions of major contributing sources and each state must impose reasonable available control technologies on these major sources by May 1995. NJDEP regulations adopted in November 1993 require that a compliance plan be filed with the NJDEP by April 15, 1994. ACE's compliance plan was filed and ACE is awaiting comment. Preliminary capital expenditures are estimated at $20 million with additional expenditures expected in the year 2000 to achieve compliance with Phase II NOx reductions. The necessary emission reductions are based on modeling results and regulatory agency discussions and could result in additional changes to equipment and in methods of operation and fuel, the extent of which has not been fully determined.
Water
The Federal Water Pollution Control Act, as amended (the Clean Water Act) provides for the imposition of effluent limitations to regulate the discharge of pollutants, including heat, into the waters of the United States. The Clean Water Act also requires that cooling water intake structures be designed to minimize adverse environmental impact. Under the Clean Water Act, compliance with applicable effluent limitations is to be achieved by a National Pollution Discharge Elimination System (NPDES) permit program to be administered by the EPA or by the state involved if such state establishes a permit program and water quality standards satisfactory to the EPA. Having previously adopted the New Jersey Pollution Discharge Elimination System (NJPDES), NJDEP assumed authority to operate the NPDES permit program. During 1981, ACE received NJPDES permits for discharges to surface waters for all facilities with existing EPA-issued NPDES permits. During 1986, ACE received draft renewal permits for both B.L. England Station and Deepwater Station for discharges to surface waters as well as groundwater. ACE filed extensive comments with the NJDEP contesting the numerous newly-imposed conditions in both permits. The NJDEP subsequently issued final permits for both stations containing certain conditions which are unacceptable to ACE. ACE filed requests for adjudicatory hearings contesting the unacceptable conditions contained in the permits. ACE has reached a resolution with the NJDEP relating to groundwater permits at B.L. England Station which required ACE to conduct additional studies, which were completed in 1991. A draft NPDES was issued in February 1994 to include past contested conditions and bring current permit limitations with respect to today's environment and technology. Most of the contested conditions were resolved with the issuance of the NPDES permit renewal effective January 1, 1995. ACE has adjudicated two minor issues related to permit conditions requiring that a pollutant reduction and a dilution study be conducted.
Effective December 2, 1974, the NJDEP adopted new surface water quality standards which, in part, provide guidelines for heat dissipation from any source and which become standards for subsequent Federal permits. These NJDEP guidelines were included in the final EPA permits issued for the B. L. England, Deepwater, Salem, and Hope Creek stations. On receipt of the permits for B. L. England and Deepwater stations, ACE filed with the EPA a request for alternative thermal limitations (variance) in accordance with the provisions of Section 316(a) of the Act. The NJDEP and EPA have subsequently determined that B. L. England Units 1 and 2 are in compliance with applicable thermal water quality standards. The request for a Section 316(a) variance for Deepwater Station has not yet been acted upon. ACE is not able at this time to predict the outcome of the request, but it believes that it has adequately supported the request for such variance. ACE believes that all of its wholly-owned steam electric generating units are, in all substantial respects, currently operating in compliance with all applicable standards and NJPDES permit limitations, except as described herein above. All current surface water discharge permits for B.L. England have been renewed as of January 1, 1995 and ACE has filed for renewal of the ground water discharge permits for B. L. England and surface water discharge permits for Deepwater. Renewal of these permits should be received this year.
The Delaware River Basin Commission (DRBC) has required various electric utilities, as a condition of being permitted to withdraw water from the Delaware River for use in connection with the operation of certain electric generating stations, to provide for a means of replacing water withdrawn from the river during certain periods of low river flow. Such a requirement presently applies to the Salem and Hope Creek Stations. As a result of such requirement, ACE and certain other electric utilities constructed the Merrill Creek Reservoir Project. ACE owns a 4.8% ownership interest in the reservoir project. Although ACE expects that sufficient replacement water would be provided by Merrill Creek during periods of low river flow to permit the full operation of Salem and Hope Creek, such events cannot be assured.
Environmental control technology, generally, is in the process of further development and the implementation of such may require, in many instances, balancing of the needs for additional quantities of energy in future years and the need to protect the environment. As a result, ACE cannot estimate the precise effect of existing and potential regulations and legislation upon any of its existing and proposed facilities and operations, or the additional costs of such regulations. ACE's capital expenditures related to compliance with environmental requirements in 1994 amounted to $57.5 million, and its most recent estimate for such compliance for the years 1995-1997 is $70.7 million. Such estimates do not include amounts which ACE may be required to expend to comply with Phase II requirements of the CAAA at B.L. England Unit 1 and Keystone Station or the normal costs of compliance with radiation protection. Such additional costs which ACE may incur in affecting compliance with potential regulations and legislation are not included in the estimated construction costs for the period 1995-1997 (see "Construction and Financing"). Future regulatory and legislative developments may require ACE to further modify, supplement or replace equipment and facilities, and may delay or impede the construction and operation of new facilities, at costs which could be substantial.
Executive Officers
Information concerning the Executive Officers of the Company and ACE, as of December 31, 1994, is set forth below. Executive Officers are elected by the respective Boards of Directors of the Company and ACE and may be removed from office at any time by a vote of a majority of all the Directors in office.
Name (age) Title(s) (effective date of election to current position(s) Jerrold L. Jacobs (55) President and Chief Executive Officer of the Company and Chairman, President and Chief Executive Officer of ACE (4/28/93). Michael J. Chesser (46) Vice President of the Company and Executive Vice President and Chief Operating Officer of ACE (2/1/94), Director of ACE. James E. Franklin II (48) Secretary and General Counsel to the Company and ACE (1/31/95), Director of ACE. Meredith I. Harlacher, Jr.(52) Vice President of the Company and Senior Vice President-Energy Supply of ACE (4/28/93), Director of ACE. Henry K. Levari, Jr. (46) Vice President of the Company (8/13/86) and Senior Vice President- Customer Operations of ACE (9/17/94), Director of ACE. Jerry G. Salomone (54) Vice President and Treasurer of the Company (8/13/86) and Senior Vice President-Finance & Administration of ACE (4/28/93), Director of ACE. (Retired 2/1/95) Frank F. Frankowski (44) Vice President-Controller, Assistant Treasurer and Assistant Secretary of ACE (7/25/94). Ernest L. Jolly (42) Vice President-Atlantic Transformation of ACE (5/23/94). J. David McCann (43) Vice President-Strategic Customer Support of ACE (4/28/93). Marilyn T. Powell (47) Vice President-Marketing of ACE (9/16/94). Henry C. Schwemm, Jr. (53) Vice President-Power Generation & Fuels Management of ACE (4/28/93). Scott B. Ungerer (36) Vice President of the Company (1/17/94). Louis M. Walters (42) Vice President-Treasurer and Assistant Secretary of ACE (1/31/95).
Prior to election to the positions above, the following officers held other positions with ACE (unless otherwise noted) since January 1, 1990:
M.J. Chesser Vice President-Marketing & Gas Operations, Baltimore Gas & Electric Company F.F. Frankowski Vice President-Controller and Assistant Treasurer of ACE (4/28/93); General Manager of Accounting Services (8/1/91). J.E. Franklin II General Counsel to the Company and ACE (10/1/94); Partner in the law firm Megargee, Youngblood, Franklin & Corcoran, P.A. M.I. Harlacher, Jr. Vice President of the Company and Senior Vice President-Utility Operations of ACE (8/9/91). J.L. Jacobs President of the Company and President and Chief Operating Officer of ACE (1/1/90). E.L. Jolly Vice President-External Affairs of ACE (3/1/92); Station Manager Deepwater Generating Station-Dupont Area for ACE. H.K. Levari, Jr. Vice President of the Company and Senior Vice President-Marketing and Customer Operations of ACE (4/28/93); Vice President of the Company and Senior Vice President-Corporate Planning and Services of ACE (8/9/91); Vice President-Power Delivery of ACE (4/24/90). J.D. McCann Vice President-Power Delivery of ACE (8/9/91). M.T. Powell Director of marketing process, International Business Machines Corporation. J.G. Salomone Senior Vice President, Finance and Accounting, Treasurer (4/22/92). H.C. Schwemm, Jr. Vice President-Production of ACE. S.B. Ungerer Manager, Business Planning Services (1/4/93); Manager, Strategic Business Planning (1/6/92); Manager, Joint Generation. L.M. Walters Vice President-Treasurer and Secretary (4/28/94); Vice President-Treasurer and Assistant Secretary (4/28/93); General Manager, Treasury and Finance (8/1/91).
ITEM 2



ITEM 2 PROPERTIES
Reference is made to the Financial Statements for information regarding investment in such property by the Company and ACE. Substantially all of ACE's electric plant is subject to the lien of the Mortgage and Deed of Trust under which First Mortgage Bonds of ACE are issued. Reference is made to Item 1 - Business "General" and "Energy Requirements and Power Supply" for information regarding ACE's properties. Information concerning leases is set forth in Note 9 of ACE's Notes to Financial Statements incorporated herein by reference. Information regarding electric generating stations is set forth in Item 1, Business-"Energy Requirements and Power Supply."
ITEM 3

ITEM 3 LEGAL PROCEEDINGS
Reference is made to Item 1 - Business and the Notes to Financial Statements of the Company (Notes 3 and 10) and ACE (Notes 3 and 8) for information regarding various pending administrative and judicial proceedings involving rate and operating and environmental matters, respectively.
ITEM 4

ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not Applicable
PART II ITEM 5

ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's Common Stock is listed on the New York, Philadelphia, and Pacific Stock Exchanges. All of ACE's Common Stock is owned by the Company. At December 31, 1994, there were 48,850 holders of record of the Company's Common Stock. The following table indicates the high and low sale prices for the Company's Common Stock as reported in the Wall Street Journal- Composite Transactions, and dividends paid for the periods indicated: Dividends High Low per Share Common Stock: First Quarter $21.750 $19.875 $ .385 Second Quarter $21.500 $16.375 $ .385 Third Quarter $19.625 $16.125 $ .385 Fourth Quarter $18.250 $16.000 $ .385
First Quarter $25.000 $21.875 $ .380 Second Quarter $23.875 $21.625 $ .380 Third Quarter $25.375 $22.625 $ .385 Fourth Quarter $23.875 $20.375 $ .385
The funds required to enable the Company to pay dividends on its Common Stock are derived primarily from the dividends paid by ACE on its Common Stock, all of which is held by the Company. Therefore the ability of the Company to pay dividends on its Common Stock will be governed by the ability of ACE to pay dividends on its Common Stock. The rate and timing of future dividends of the Company will depend upon the earnings and financial condition of the Company and its subsidiaries, including ACE, and upon other factors affecting dividend policy not presently determinable. ACE is subject to certain limitations on the payment of dividends to the Company. Whenever full dividends on Preferred Stock have been paid for all past quarter-yearly periods, ACE may pay dividends on its Common Stock from funds legally available for such purpose. Until all cumulative dividends have been paid upon all series of Preferred Stock and until certain required sinking fund redemptions of such Preferred Stock have been made, no dividend or other distribution may be paid or declared on the Common Stock of ACE and no Common Stock of ACE shall be purchased or otherwise acquired for value by ACE. In addition, as long as any Preferred Stock is outstanding, ACE may not pay dividends or make other distributions to the holder of its Common Stock if, after giving effect to such payment or distribution, the capital of ACE represented by its Common Stock, together with its surplus as then stated on its books of account, shall in the aggregate, be less than the involuntary liquidation value of the then outstanding shares of Preferred Stock.
ITEM 6

ITEM 6 SELECTED FINANCIAL DATA Selected financial data for the Company and ACE for each of the last five years is listed below.
Atlantic City Electric Company
1994 1993 1992 1991 1990 (Thousands of Dollars)
Operating Revenues $ 913,226 $ 865,799 $ 816,931 $ 808,482 $ 741,005 Net Income $ 93,174 $ 109,026 $ 107,446 $ 107,428 $ 80,176 Earnings for Common Shareholder (a) $ 76,458 $ 91,621 $ 89,634 $ 91,017 $ 69,377 Total Assets (Year-end) $2,421,316 $2,363,584 $2,100,278 $2,042,859 $1,903,326 Long Term Debt and Redeemable Preferred Stock (Year-end)(b) $ 924,788 $ 937,101 $ 817,108 $ 768,247 $ 708,977 Capital Lease Obligations (Year-end)(b) $ 42,030 $ 45,268 $ 49,303 $ 53,093 $ 57,971 Common Dividends Declared (a) $ 83,482 $ 81,347 $ 78,336 $ 74,073 $ 67,085
(a) Amounts shown as total, rather than on a per-share basis, since ACE is a wholly-owned subsidiary of the Company. (b) Includes current portion. /TABLE
ITEM 7

ITEM 7 Management's Discussion and Analysis of Financial Condition and Results of Operations
Atlantic Energy, Inc. (the Company, AEI or parent) is the parent of a consolidated group of wholly-owned subsidiaries consisting of Atlantic City Electric Company (ACE) and the following nonutility companies: Atlantic Energy Technology, Inc. (AET), Atlantic Generation, Inc. (AGI), Atlantic Southern Properties, Inc. (ASP), ATE Investment, Inc. (ATE) and Atlantic Thermal Systems, Inc. (ATS). ACE, the primary subsidiary, is an electric utility regulated by the New Jersey Board of Public Utilities (BPU). ACE has a wholly-owned subsidiary that operates certain generating facilities. AGI is engaged in the development and operation of cogeneration and alternate energy projects through various partnership arrangements. ASP owns and manages a commercial real estate property. ATE manages a portfolio of leveraged lease investments and provides financing and fund management to an affiliate. ATS is engaged with development of district heating and cooling facilities which it intends to own and operate. AET is presently concluding the affairs of its subsidiary which is its sole investment. On January 1, 1995, a new subsidiary of AEI, Atlantic Energy Enterprises, Inc. (AEE), was formed. AEI will transfer direct ownership of the existing nonutility companies to AEE.
The Company's business plan will concentrate on the core utility operations of ACE and the expansion of non-utility business opportunities related to the core business. The emergence of competition in the area of electric generation, slower growth in energy sales, Federal deregulation of wholesale energy sales, prospective retail wheeling initiatives coupled with a public utility's obligation to serve and the need to mitigate future rate increases has caused ACE to re-examine its traditional approach to its business. ACE's current business plan recognizes the increasingly competitive nature of the electric energy business in general and the need to encourage economic growth and stability in the service territory and surrounding region. ACE is re-evaluating its revenue requirements and service pricing, the implementation of additional cost controls and the development of new sources of revenue. Nonutility business strategies are expected to pursue new investment opportunities closely related to the utility business, primarily in the areas of nonregulated electric generation, energy technology investments and thermal energy systems. Investments in these areas may take place as direct ownership or in partnership with others.
Financial Results
Consolidated operating revenues for 1994, 1993 and 1992 were $913.0 million, $865.7 million and $816.8 million, respectively. The increase in 1994 revenue reflects an increase in Levelized Energy Clause (LEC) revenues as a result of a $55.0 million rate increase effective July 1994 and an increase in sales for resale. The increased revenues for 1993 reflect the effect of a rate increase of $10.9 million effective in that year. The revenue increase in 1993 also reflects the contrast between the 1993 normal and the 1992 below normal summer temperatures.
Consolidated earnings per share for 1994 were $1.41 on net income of $76.1 million, compared with $1.80 on net income of $95.3 million in 1993 and $1.67 on net income of $86.2 million in 1992. The 1994 earnings were attributable solely to ACE and include a reduction of $.32 for employee separation programs and $.02 for the write-off of deferred nuclear study costs. In 1993, ACE contributed $1.73 to consolidated earnings, primarily as a result of increased kilowatt-hour sales due to the contrast between 1993 and 1992 summer temperatures. ACE's 1993 earnings were reduced by $.10 as a result of charges for reorganization activities. In 1992, ACE contributed $1.74 to consolidated earnings, which included $.15 for a litigation settlement with PECO Energy.
Nonutility operations resulted in a net loss of $345 thousand for 1994, net income of $3.7 million for 1993 and a net loss for 1992 of $3.4 million. The net loss for 1994 reflects the write-down of carrying value of ASP's commercial site in the amount of $1.7 million after tax, or $.03 per share. This was offset, in part, by the earnings of AGI. Non-utility net income for 1993 was primarily the result of higher earnings of AGI derived from the first full year's commercial operation of two of its cogeneration projects. The loss in 1992 was primarily due to provisions made by AET relating to restructuring of certain business activities. That loss was offset, in part, by earnings of AGI resulting from the start-up of two of AGI's cogeneration projects and by ATE's lower interest expense.
The quarterly dividend paid on Common Stock was $.385 per share, or an annual rate of $1.54 per share. Information with respect to Common Stock for the period 1992-1994 is as follows:
1994 1993 1992
Dividends Paid Per Share $ 1.54 $ 1.53 $ 1.51 Book Value Per Share $15.56 $15.62 $15.17 Annualized Dividend Yield 8.7% 7.0% 6.6% Return on Average Common Equity 9.1% 11.7% 11.1% Total Return (Dividends paid plus change in share price) (11.9)% 0.6% 20.2% Market to Book Value 113% 139% 152% Price/Earnings Ratio 13 12 14 Closing Price-New York Stock Exchange $17.63 $21.75 $23.13
Liquidity and Capital Resources
Overview
The Company's cash flows are dependent on the cash flows of its subsidiaries, primarily ACE. Principal cash inflows of the Company are dividends from ACE and funds provided by the issuance of Common Stock. Principal cash outflows of the Company are investments (capital contributions and advances) in its subsidiaries for their investing activities, dividends to common shareholders and repurchase of outstanding common stock. Cash invested in ACE is utilized primarily for the construction of utility generation, transmission and distribution facilities, re- demption and maturity of long and short term debt and redemption of preferred stock. Current investing activities of the nonutility subsidiaries are primarily for the development of nonutility power generation projects and thermal heating and cooling systems.
Agreements between the Company and its subsidiaries provide for allocation of tax liabilities and benefits generated by the respective subsidiaries. A separate credit support agreement exists between the Company and ATE.
In 1994, 1993 and 1992, the Company recorded $83.2 million, $81.3 million and $78.3 million, respectively, in dividends from ACE. Other sources of funds available to the Company, which include the issuance of common equity through optional cash purchases under the Dividend Reinvestment and Stock Purchase Plan (DRP) through July 1994 and ACE's employee benefit plans, are shown as follows:
1994 1993 1992 DRP Optional Cash Purchases Shares issued 336,193 690,466 719,324 Proceeds (000) $6,737 $15,985 $16,034 Employee Benefit Plans Shares issued - 8,033 10,897 Proceeds (000) $ - $258 $259
Additional common equity has been provided by reinvested divi- dends through the DRP. In June 1994, the Company discontinued the issuance of new Common Stock through the DRP, except for certain employee benefit plans. Common shares issued from reinvested dividends in 1994, 1993 and 1992 were 370,654, 609,663 and 572,329, respectively.
Major cash outflows of the Company were as follows:
1994 1993 1992 (Millions) Dividends to Shareholders $83.2 $81.3 $78.3 Advances and Capital Contributions to Subsidiaries* $25.6 $29.8 $24.1
* Net of Repayments
On October 27, 1994, the Company's Board of Directors authorized the Company to acquire up to three million shares of Common Stock. The Company will cancel these shares. As of December 31, 1994, the Company has acquired and cancelled 221,700 shares at a cost of $3.9 million.
Atlantic City Electric Company
Cash construction expenditures for the 1992-1994 period amounted to $388.8 million and included expenditures for upgrades to existing transmission and distribution facilities and compliance with provisions of the Clean Air Act Amendments (CAAA) of 1990. ACE's current estimate of cash construction expenditures for the 1995-1997 period is $268 million. These estimated expenditures reflect necessary improvements to transmission and distribution facilities and further compliance with provisions of the CAAA.
ACE also utilizes cash for mandatory redemptions of Preferred Stock and maturities and redemption of long term debt. Optional redemptions of securities are reviewed on an ongoing basis with a view toward reducing the overall cost of funds.
Redemptions of Preferred Stock (at par or stated value)for the period 1992-1994 are shown as follows:
1994 1993 1992 Preferred Stock (Series) 9.96% (Shares) - 48,000 8,000 $8.53 (Shares) 240,000 - - $8.25 (Shares) 5,000 5,000 2,500
Aggregate Amount (000) $24,500 $5,300 $1,050
First Mortgage Bonds redeemed or acquired and retired or matured in the period 1992-1994 were as follows:
Date Series Principal Amount Price(%) (000)
November 1994 7-5/8% due 2005 $ 6,500 100.00 June 1994 10-1/2% due 2014 23,150 102.00 Various 1994 Dates 9-1/4% due 2019 11,910 105.38* September 1993 9-1/4% due 2019 69,233 110.95* September 1993 8-7/8% due 2016 125,000 104.80 March 1993 8-7/8% due 2000 19,000 102.41 March 1993 8% due 2001 27,000 102.53 March 1993 8% due 1996 95,000 100.91 March 1993 4-3/8% due 1993 9,540 100.00 July 1992 4-1/2% due 1992 10,350 100.00
* Average price
Scheduled debt maturities and sinking fund requirements aggregate $69 million for the years 1995-1997.
On or before April 1 of each year, ACE and other New Jersey utilities are required to pay gross receipts and franchise taxes (state excise taxes) to the State of New Jersey. In March 1994, ACE paid $137.5 million. Included in that amount was approximately $50 million representing the second and final installment for the additional one-half year's amount of tax due as required by amended state law. This additional amount of gross receipts and franchise tax payment, plus the additional one-half year's payment in 1993 of $45 million, has been recorded on the Consolidated Balance Sheet as Unrecovered State Excise Taxes and is being recovered through rates by ACE. In December 1993, ACE paid $20 million in connection with renegotiation of a nonutility purchase power contract which ACE is recovering through its LEC. The estimated savings of this renegotiation, based on currently forecasted fuel costs, is $15 million to $20 million per year, net of the $20 million payment.
On an interim basis, ACE finances that portion of its con- struction costs and other capital requirements in excess of internally generated funds through the issuance of unsecured short term debt consisting of commercial paper and borrowings from banks. As of December 31, 1994, ACE has arranged for lines of credit of $150 million of which $141.4 million was available. Permanent financing by ACE is undertaken by the issuance of its long term debt and Preferred Stock and from capital contributions by the parent company. ACE's nuclear fuel requirements associated with its jointly-owned units have been financed through arrangements with a third party.
In 1994, ACE issued and sold $54.65 million of its long term debt consisting of Pollution Control Bonds. The proceeds from the financings were used for refunding higher cost Pollution Control Bonds and for construction purposes. Additionally, $125 million in debt securities were registered and are available for issuance in 1995. In 1993, ACE issued and sold $469 million of long term debt consisting of $240 million of Series B Medium Term Notes, $225 million of First Mortgage Bonds and $4 million of Pollution Control Bonds. The proceeds from the 1993 financings were also used for refunding higher cost debt and construction purposes. In 1992, ACE issued and sold $60 million of Series A Medium Term Notes, the proceeds of which were used for ACE's construction program. During 1995-1997, ACE expects to issue $50 million in new long term debt to be used for funding of construction and repayment of short term debt.
Provisions of ACE's charter, mortgage and debenture agreements can limit, in certain cases, the amount and type of additional financing which may be used. At December 31, 1994, ACE estimates additional funding capacities of $218 million of First Mortgage Bonds, or $530 million of Preferred Stock, or $432 million of unsecured debt. These amounts are not necessarily additive.
Non-Utility Companies
Management of the nonutility companies is evaluating business opportunities which are expected to enhance nonutility operations over the next five years, with focused efforts on expanding and improving its financial performance in nonutility activities. Matters specific to each of the nonutility companies are discussed below.
Atlantic Energy Enterprises, Inc.
On January 1, 1995, AEI formed a new subsidiary, Atlantic Energy Enterprises, Inc. (AEE), which will hold ownership of the existing nonutility businesses of AGI, ASP, ATE, ATS, and AET. As part of this reorganization, AEE expects to develop an organization structured to allow greater flexibility to pursue non-regulated business opportunities. Expansion of business is expected to focus in the areas of non-regulated electric generation, energy technology investments and thermal energy systems. Investments in these areas may take place as direct ownership or in partnership with others. AEE's business plan reflects the potential investment of approximately $215 million over the next five years. AEE will have its own Board of Directors, including outside directors which will help to guide the non-regulated enterprises.
Atlantic Generation, Inc.
AGI's activities are represented by partnership interests in three cogeneration projects. At December 31, 1994, total investments amounted to $24.6 million. Cash outlays for investments (comprised of capital investment, advances and loans) by AGI for the period 1992-1994 totaled $14.6 million. AGI obtained the funds for its investments through capital contributions from the parent company. During the period 1992- 1994, AGI received distributions from the partnerships totaling $4.4 million from return of investment and repayment of outstanding advances and loans. In June 1994, the third cogeneration project became operational. AGI expects to continue investment in additional domestic independent power projects in the years 1995-1999.
Atlantic Southern Properties, Inc.
ASP's real estate investment at December 31, 1994 is a 280,000 square-foot office and warehouse facility in Atlantic County, New Jersey. This investment has a net book value of $10.3 million after a write-down of the carrying value in 1994 of $2.6 million reflecting diminished value due to excess vacancy. As of December 31, 1994, ASP's investment has been funded by capital contributions from the parent company and borrowings under a loan agreement with ATE. ASP's current agreement with ATE provides for the repayment of such borrowings on or before December 31, 1995. Extensions to repay these borrowings have been routinely granted in the past. No real estate activity beyond the existing site is contemplated at this time by ASP.
ATE Investment, Inc.
ATE has invested $78.2 million in leveraged leases of three commercial aircraft and two containerships. ATE has loans outstanding to ASP which totaled $8.7 million at December 31, 1994. ATE obtained funds for its business activities and loans to ASP through capital contributions from the parent company and external borrowings which include $15 million principal amount of 7.44% Senior Notes due 1999 and a revolving credit and term loan facility for borrowings of up to $35 million. At December 31, 1994, there was $1 million in borrowings outstanding under this facility. ATE's cash flows are provided from lease rental receipts and realization of existing tax benefits generated by the leveraged leases sufficient to sustain operations.
Atlantic Thermal Systems, Inc.
ATS is presently engaged in the development of thermal heating and cooling systems. ATS has obtained funds for its project development through advances from the parent company and has established a $10 million revolving credit agreement with ATE. There were no loans outstanding from this agreement as of December 31, 1994.
Atlantic Energy Technology, Inc.
AET is currently concluding the affairs of its subsidiary, which is its sole investment. The net investment in this subsidiary is nominal. The amount of this investment was written down in 1993 as a result of planned reorganization activities that were provided for in 1992. At that time the subsidiary discontinued its operations to concentrate on licensing its proprietary knowledge. In 1993, AET received life insurance proceeds of $500 thousand through its subsidiary. There are no future plans for investment activity at this time by AET.
RESULTS OF OPERATIONS
Operating results are dependent upon the performance of the subsidiaries, primarily ACE. Since ACE is the principal subsidiary within the consolidated group, the operating results presented in the Consolidated Statement of Income are those of ACE, after elimination of transactions among members of the consolidated group. Results of the nonutility companies are reported in Other Income.
Revenues
Operating Revenues - Electric increased 5.5% and 6.0% in 1994 and 1993, respectively. Components of the overall changes are shown as follows:
(millions) 1994 1993
Base Revenues $(4.2) $12.2 Levelized Energy Clauses 30.3 (5.0) Kilowatt-hour Sales 9.6 42.6 Unbilled Revenues (7.3) (1.2) Sales for Resale 17.8 0.7
Other 1.2 (0.4)
Total $47.4 $48.9
Levelized Energy Clause (LEC) revenues increased in 1994 due to rate increases of $55 million in July 1994 and $10.9 million in October 1993. The decrease in 1993 LEC revenues was the net result of the increase in October 1993 and an $8.5 million decrease effective October 1992. Changes in kilowatt-hour sales are discussed under "Billed Sales to Ultimate Utility Customers." Overall, the combined effects of changes in rates charged to customers and kilowatt-hour sales resulted in increases of 3.1% and 0.8% in revenues per kilowatt-hour in 1994 and 1993, respectively. The changes in Unbilled Revenues are a result of the amount of kilowatt-hours consumed by ultimate customers at the end of the respective periods, which are affected by weather and economic conditions, and the corresponding price per kilowatt-hour. The changes in Sales for Resale are a function of ACE's energy mix strategy, which in turn is dependent upon ACE's needs for energy, the energy needs of other utilities participating in the regional power pool of which ACE is a member, and the sources and prices of energy available. The increase in Sales for Resale for 1994 was the result of meeting the demands of the regional power pool due to the extreme weather conditions during the first six months of 1994.
Effective July 1, 1994, the BPU permitted hotel-casino customers to take service under existing commercial rate schedules which is expected to reduce annual revenue by approximately $7 million.
Billed Sales to Ultimate Utility Customers
Changes in kilowatt-hour sales are generally due to changes in the average number of customers and average customer use, which is affected by economic and weather conditions. Energy sales statistics, stated as percentage changes from the previous year, are shown as follows:
1994 1993
Avg Avg # Avg Avg # Customer Class Sales Use of Cust Sales Use of Cust
Residential 1.5% .4% 1.1% 6.7% 5.9% .8% Commercial 2.6 .5 2.1 5.1 3.2 1.9 Industrial (2.9) (3.8) .9 2.6 4.6 (1.9) Other 3.2 4.0 (.8) 1.2 1.6 (.4) Total 1.3 - 1.2 5.4 4.4 .9
The 1994 increase in total kilowatt-hour sales was due to the extreme weather conditions during the first quarter of 1994 and an increased number of billing days in 1994 compared to 1993. This increase was partially offset by the abnormal weather conditions during the last half of the year when kilowatt-hour usage fell below 1993 levels. In 1993, total kilowatt-hour sales increased primarily due to the colder winter temperatures during the first quarter, and below normal temperatures during the summer of 1992. Improved economic conditions also contributed to the increase in 1993 sales. Commercial sales in both years benefitted from night lighting programs. The decline in 1994 industrial sales is due to the loss of ACE's largest customer to an independent power producer during the year.
Costs and Expenses
Total Operating Expenses increased 7.6% and 3.9% in 1994 and 1993, respectively. Included in these expenses are the costs of energy, purchased capacity, operations, maintenance, depreciation and taxes.
Energy expense reflects cost incurred for energy needed to meet load requirements, various energy supply sources used and operation of the LECs. Changes in costs reflect the varying availability of low-cost generation from ACE-owned and purchased energy sources, and the corresponding unit prices of the energy sources used, as well as changes in the needs of other utilities participating in the Pennsylvania-New Jersey-Maryland Interconnection. The cost of energy is recovered from customers primarily through the operation of the LEC. Until 1994, earnings were generally not affected by energy costs because these costs are adjusted to match the associated LEC revenues. In any period, the actual amount of LEC revenue recovered from customers may be greater or less than the actual amount of energy cost incurred in that period. Such respective overrecovery or underrecovery of energy costs is recorded on the Consolidated Balance Sheet as a liability or an asset as appropriate. Amounts in the balance sheet are recognized in the Consolidated Statement of Income within Energy expense during the period in which they are subsequently recovered through the LEC. ACE was underrecovered by $11 million and by $7.2 million at December 31, 1994 and 1993, respectively.
As a result of implementing the Southern New Jersey Economic Initiative in rates, effective July 19, 1994, the Company is forgoing recovery of future energy costs in LEC rates of $28 million through May 31, 1995. After tax income has been reduced by $10.1 million due to the effects of this initiative in 1994.
In 1994, Energy expense increased 32.7% due to the adoption of the Southern New Jersey Economic Initiative and the increase in the levelized energy clause that reduced underrecovered fuel costs. Production-related energy costs for 1994 increased by 19.9% due to increased overall generation and the high cost of energy from additional nonutility sources. The average unit cost for energy in 1994 increased to 2.04 cents per kilowatt-hour compared to 1.82 cents per kilowatt-hour in 1993. Energy expense for 1993 decreased 1.1% primarily due to an increase in underrecovered fuel costs in 1993 compared to 1992. Production- related energy cost for 1993 increased by 6.7% largely due to increased generation. The average unit cost for energy in 1993 increased to 1.82 cents per kilowatt-hour compared to 1.8 cents per kilowatt-hour in 1992. The 1993 increase in the per unit cost is a result of increased amounts of higher cost energy from nonutility sources and a decreased supply of lower cost energy from coal sources.
Purchased Capacity expense reflects entitlements to generating capacity owned by others. Purchased Capacity expense increased 18.2% and 7.4% in 1994 and 1993, respectively. The increases in Purchased Capacity reflect additional capacity supplied by nonutility power producers that became operational in each year.
Operations expense decreased 3.5% in 1994 and increased 8.9% in 1993. The increase in 1993 was due primarily to corporate reorganization activities by ACE. Maintenance expense decreased 17.2% in 1994 due to cost saving measures in maintenance activities. The 9% decrease in 1993 maintenance expense was due to the scheduling of maintenance projects.
Depreciation and Amortization expense increased 7.9% in 1994 as a result of an increase in the depreciable base of ACE's electric plant in service. State Excise Taxes expense decreased 6.9% in 1994 and increased by 6.4% in 1993. The increase in 1993 is due to a higher tax assessment.
Federal Income Taxes decreased 6.1% in 1994 and increased 21.9% in 1993 as a result of the level of taxable income during those periods. The change in the 1993 amount reflects the increase in the Federal income tax rate to 35% from 34%, effective in that year.
Employee Separation costs represents programs by ACE to reduce its workforce by about 20%, or 350 people. Other-Net within Other Income (Expense) decreased in 1994 due to the net after tax impacts of the write-off of deferred nuclear study costs of $1.4 million and the write-down of the carrying value of ASP's commercial property of $1.7 million. Litigation Settlement in 1992 represents ACE's share of the settlement of litigation concerning the Nuclear Regulatory Commission imposed shutdown in earlier years of the Peach Bottom Atomic Power Station. The Litigation Settlement for 1993 represents an additional allocation to customers of the proceeds from the 1992 settlement as ordered by the BPU. Other-Net increased for 1993 as a result of the first full year operation of AGI's cogeneration projects.
Interest on Long Term Debt decreased in 1994 due to refunding of higher cost debt. Interest on Long Term Debt increased 11.4% in 1993 reflecting the net effects of issuance of $469 million of First Mortgage Bonds during the year, and the maturity, redemption and reacquisition of various series of First Mortgage Bonds totaling $344.8 million principal amount. At December 31, 1994, 1993 and 1992, ACE's embedded cost of long term debt was 7.6%, 7.8% and 8.8%, respectively.
Preferred Stock Dividend Requirements decreased as a result of continuing mandatory and optional redemptions in each year. Embedded cost of Preferred Stock as of December 31, 1994, 1993 and 1992 was 7.6%, 7.7% and 7.7%, respectively.
Outlook
The nature of the electric utility business is capital intensive. ACE's ability to generate cash flows from operating activities and its continued access to the capital markets is affected by the timing and adequacy of rate relief, competition and the economic vitality of its service territory. ACE has lowered its planned capital expenditures for the period 1995-1999 which will reduce its external cash requirements. Additionally, ACE expects to review its revenue requirements with a view toward overall rate stability in light of expected price competition. ACE believes one of its greatest assets is its high level of customer service and reliability.
The financial performance of ACE will be affected in the future by the level of sales of energy and the impacts of regulation and competition. To better position itself for a more competitive environment, ACE initiated cost reduction programs in 1994. One such program was a workforce reduction program which ACE expects will result in annual after tax cost savings in excess of $10 million. Other issues which may impact the electric utility business include public health, safety and environmental legislation.
Changes in operating revenues in the future will result from changes in customer rates, energy consumption and general economic conditions in the service area, as well as the impacts of load management and conservation programs instituted by ACE. ACE's revenues could also be affected by the increasing competition in the retail and wholesale energy market. The emergence of competition among suppliers of electricity may require ACE to create new rate structures and to offer incentives to its Commercial and Industrial customers.
Net income of ACE may be affected by the operational performance of nuclear generating facilities. ACE is subject to a BPU-mandated nuclear unit performance standard. Under the standard, penalties or rewards are based on the aggregate capacity factor of ACE's five jointly-owned nuclear units. Any penalties incurred would not be permitted to be recovered from customers and would be charged against income.
The Energy Policy Act, enacted in October 1992, provides, among other things, for increased competition between utility and non- utility electric generators and permits wholesale transmission access, or wheeling, with certain requirements. Other pressures such as increased customer demands for competitive rates, potential loss of municipal power sales, excess generating capacity, together with the emergence of nonutility energy sources, are expected to increase the amount of business risk for electric utilities in the future. In addition, the extent to which New Jersey public utility regulation is modified to be reflective of these new competitive realities will be a key factor affecting the Company.
Development of electric generating facilities by nonutilities has occurred in ACE's service territory. Effects of nonutility generation could be offset to some extent by natural growth in the service territory and additional efforts by ACE to reduce the impact of the potential loss of kilowatt-hour sales and revenues.
The CAAA will require modifications at certain of ACE's facilities. Compliance with the CAAA will cause ACE to incur additional operating and/or capital costs. Presently, ACE's construction budget for 1995 through 1997 includes approximately $16 million related to the cost of compliance. In addition, certain power purchase arrangements will be affected by the CAAA, the effects of which are not presently determinable.
Federal and state legislation authorize various governmental authorities to issue orders compelling responsible parties to take cleanup action at sites determined to present danger from releases of hazardous substances. The various statutes impose joint and several liability without regard to fault for certain investigative and cleanup costs for all potentially responsible parties. ACE has received notification with respect to two sites within New Jersey as one of a number of alleged responsible parties for cleanup and remedial actions. ACE's responsibility is not expected to exceed $1 million in the aggregate.
The Company believes that to continue to be successful it will need to focus on improving the core utility operations of ACE to meet expected competition, while identifying opportunities for new businesses and growth in earnings through AEE. With support from the Board of Directors, management has embarked on implementing an aggressive business plan which it believes will position the Company to meet the challenges of a new competitive environment.
Inflation
Inflation affects the level of operating expenses and also the cost of new utility plant placed in service. Traditionally, the rate making practices that have applied to ACE have involved the use of historical test years and the actual cost of utility plant. However, the ability to recover increased costs through rates, whether resulting from inflation or otherwise, depends upon the frequency, timing and results of rate case decisions.
ITEM 8


ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF MANAGEMENT
The management of Atlantic Energy, Inc. and its subsidiaries (the Company) is responsible for the preparation of the financial statements presented in this Annual Report. The financial statements have been prepared in conformity with generally accepted accounting principles. In preparing the financial statements, management made informed judgments and estimates, as necessary, relating to events and transactions reported. Management is also responsible for the preparation of other financial information included elsewhere in this Annual Report.
Management has established a system of internal accounting and financial controls and procedures designed to provide reasonable assurance as to the integrity and reliability of financial reporting. In any system of financial reporting controls, inherent limitations exist. Management continually examines the effectiveness and efficiency of this system, and actions are taken when opportunities for improvement are identified. Management believes that, as of December 31, 1994, the system of internal accounting and financial controls over financial reporting is effective. Management also recognizes its responsibility for fostering a strong ethical climate in which the Company's affairs are conducted according to the highest standards of corporate conduct. This responsibility is characterized and reflected in the Company's code of ethics and business conduct policy.
The financial statements have been audited by Deloitte & Touche LLP, Certified Public Accountants. Deloitte & Touche LLP provides objective, independent audits as to management's discharge of its responsibilities insofar as they relate to the fairness of the financial statements. Their audits are based on procedures believed by them to provide reasonable assurance that the financial statements are free of material misstatement.
The Company's internal auditing function conducts audits and appraisals of the Company's operations. It evaluates the system of internal accounting, financial and operational controls and compliance with established procedures. Both the external auditors and the internal auditors periodically make recommendations concerning the Company's internal control structure to management and the Audit Committee of the Board of Directors. Management responds to such recommendations as appropriate in the circumstances. None of the recommendations made for the year ended December 31, 1994 represented significant deficiencies in the design or operation of the Company's internal control structure.
J. L. Jacobs F. F. Frankowski President and Chief Accounting Officer Chief Executive Officer
February 9, 1995 REPORT OF THE AUDIT COMMITTEE
The Audit Committee of the Board of Directors is comprised solely of independent directors. The members of the Committee are: Jos. Michael Galvin, Jr., Gerald A. Hale, Matthew Holden, Jr., Kathleen MacDonnell and Harold J. Raveche. The Committee held four meetings during 1994.
The Committee oversees the Company's financial reporting process on behalf of the Board of Directors. In fulfilling its responsibility, the Committee recommended to the Board of Directors, subject to shareholder ratification, the selection of the Company's independent auditors, Deloitte & Touche LLP . The Committee discussed with the Company's internal auditors and Deloitte & Touche LLP the overall scope of and specific plans for their respective activities concerning the Company. The Committee also discussed the Company's consolidated financial statements with Deloitte & Touche LLP. The Committee meets regularly with the internal and external auditors, without management present, to discuss the results of their activities, the adequacy of the Company's system of accounting, financial and operational controls and the overall quality of the Company's financial reporting. The meetings are designed to facilitate any private communication with the Committee desired by the internal and external auditors. No significant actions by the Committee were required during the year ended December 31, 1994 as a result of any private communications conducted.
Matthew Holden, Jr. Chairman, Audit Committee
February 9, 1995 INDEPENDENT AUDITORS' REPORT
To the Shareholders and the Board of Directors of Atlantic Energy, Inc.:
We have audited the accompanying consolidated balance sheets of Atlantic Energy, Inc. and subsidiaries as of December 31, 1994 and 1993 and the related consolidated statements of income, changes in common shareholders' equity, and cash flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Atlantic Energy, Inc. and its subsidiaries at December 31, 1994 and 1993 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
February 9, 1995 Parsippany, New Jersey CONSOLIDATED STATEMENT OF INCOME Atlantic Energy, Inc. and Subsidiaries (Thousands of Dollars) For the Years Ended December 31, 1994 1993 1992
Operating Revenues-Electric $913,039 $865,675 $816,825
Operating Expenses: Energy 210,891 159,438 161,134 Purchased Capacity 130,929 110,781 103,173 Operations 156,409 162,151 148,917 Maintenance 37,568 45,360 49,837 Depreciation and Amortization 73,344 67,950 69,371 State Excise Taxes 97,072 104,280 97,969 Federal Income Taxes 42,529 45,277 37,143 Other Taxes 10,757 10,854 12,113 Total Operating Expenses 759,499 706,091 679,657
Operating Income 153,540 159,584 137,168
Other Income and Expense: Allowance for Equity Funds Used During Construction 3,634 2,368 2,212 Employee Separation Costs, net of tax of $9,265 (17,335) - - Litigation Settlement, net of tax of: 1993-$(1,321); 1992-$4,982 - (2,564) 9,671 Other-Net 8,678 12,884 9,519 Total Other Income and Expense (5,023) 12,688 21,402
Income Before Interest Charges 148,517 172,272 158,570
Interest Charges: Interest on Long Term Debt 57,346 59,385 53,284 Other Interest Expense 1,114 1,633 2,678 Total Interest Charges 58,460 61,018 55,962 Allowance for Borrowed Funds Used During Construction (2,772) (1,448) (1,414) Net Interest Charges 55,688 59,570 54,548
Less Preferred Stock Dividend Requirements of Subsidiary 16,716 17,405 17,812
Net Income $ 76,113 $ 95,297 $ 86,210
Average Number of Shares of Common Stock Outstanding (in thousands) 54,149 52,888 51,592
Per Common Share: Earnings $1.41 $1.80 $1.67
Dividends Declared $1.54 $1.535 $1.515
Dividends Paid $1.54 $1.53 $1.51
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. CONSOLIDATED STATEMENT OF CASH FLOWS Atlantic Energy, Inc. and Subsidiaries (Thousands of Dollars) For the Years Ended December 31, 1994 1993 1992 Cash Flows Of Operating Activities: Net Income $ 76,113 $ 95,297 $ 86,210 Deferred Purchased Power Costs 14,920 (6,050) 13,410 Deferred Energy Costs (3,819) (15,269) (6,143) Preferred Stock Dividend Requirements of Subsidiary 16,716 17,405 17,812 Depreciation and Amortization 73,344 67,950 69,371 Deferred Income Taxes-Net 17,863 20,901 23,386 Prepaid State Excise Taxes (37,029) (35,982) 540 Employee Separation Costs 26,600 - - Net (Increase) Decrease in Other Working Capital (24,571) 32,364 7,685 Other-Net (2,457) 1,534 5,650 Net Cash Provided by Operating Activities 157,680 178,150 217,921
Cash Flows Of Investing Activities: Utility Cash Construction Expenditures (119,961) (138,111) (130,700) Leased Property (10,713) (9,946) (9,565) Nuclear Decommissioning Trust Fund Deposits (6,424) (6,424) (6,424) Other-Net (11,276) (9,832) (8,524) Net Cash Used by Investing Activities (148,374) (164,313) (155,213)
Cash Flows Of Financing Activities: Proceeds from Long Term Debt 54,572 464,633 74,655 Retirement and Maturity of Long Term Debt (42,664) (370,541) (40,599) Increase (Decrease) in Short Term Debt 8,600 (14,600) (6,000) Proceeds from Common Stock Issued 10,289 16,208 16,110 Repurchase of Common Stock (3,909) - - Redemption of Preferred Stock (24,500) (5,469) (250) Dividends Declared on Preferred Stock (16,716) (17,405) (17,812) Dividends Declared on Common Stock (75,829) (67,259) (65,644) Other-Net 12,330 8,584 4,412 Net Cash (Used) Provided by Financing Activities (77,827) 14,151 (35,128) Net (Decrease) Increase in Cash and Temporary Investments (68,521) 27,988 27,580 Cash and Temporary Investments, beginning of year 73,635 45,647 18,067 Cash and Temporary Investments, end of year $ 5,114 $ 73,635 $ 45,647
Supplemental Schedule of Payments: Interest $ 62,855 $ 52,765 $ 55,275 Income taxes $ 23,374 $ 19,565 $ 24,312
Noncash Financing Activities: Common Stock issued under stock plans $ 7,652 $ 14,088 $ 12,692
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. CONSOLIDATED BALANCE SHEET Atlantic Energy, Inc. and Subsidiaries (Thousands of Dollars) December 31, 1994 1993 Assets Electric Utility Plant: In Service: Production $1,151,661 $1,054,217 Transmission 357,389 338,584 Distribution 659,619 627,649 General 180,204 173,206 Total In Service 2,348,873 2,193,656 Less Accumulated Depreciation 725,999 668,832 Net 1,622,874 1,524,824 Construction Work in Progress 110,078 156,590 Land Held for Future Use 6,941 6,901 Leased Property-Net 42,030 45,268 Electric Utility Plant-Net 1,781,923 1,733,583
Investments and Nonutility Property: Investment in Leveraged Leases 78,216 77,268 Nuclear Decommissioning Trust Fund 52,004 43,163 Nonutility Property and Equipment-Net 18,163 14,535 Other Investments and Funds 28,940 18,102 Total Investments and Nonutility Property 177,323 153,068
Current Assets: Cash and Temporary Investments 5,114 73,635 Accounts Receivable: Utility Service 54,554 51,502 Miscellaneous 14,067 11,420 Allowance for Doubtful Accounts (3,300) (3,000) Unbilled Revenues 32,070 39,309 Fuel (at average cost) 28,030 14,635 Materials and Supplies (at average cost) 27,823 28,230 Working Funds 14,475 14,315 Deferred Energy Costs 10,999 7,180 Deferred Income Taxes 12,264 3,283 Other 11,883 15,796 Total Current Assets 207,979 256,305
Deferred Debits: Unrecovered Purchased Power Costs 115,538 130,458 Recoverable Future Federal Income Taxes 85,854 85,855 Unrecovered State Excise Taxes 73,834 33,706 Unamortized Debt Costs 38,184 39,306 Other Regulatory Assets 47,055 41,705 Other 17,865 13,522 Total Deferred Debits 378,330 344,552
Total Assets $2,545,555 $2,487,508
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
Atlantic Energy, Inc. and Subsidiaries (Thousands of Dollars) December 31, 1994 1993
Liabilities and Capitalization Capitalization: Common Shareholders' Equity: Common Stock, no par value; 75,000,000 shares authorized; issued and outstanding: 1994 - 54,155,245; 1993 - 53,506,786 $ 593,475 $ 579,443 Retained Earnings 249,181 256,549 Total Common Shareholders' Equity 842,656 835,992 Preferred Stock of Atlantic City Electric Company: Not Subject to Mandatory Redemption 40,000 40,000 Subject to Mandatory Redemption 149,250 173,750 Long Term Debt 778,288 766,101 Total Capitalization (excluding current portion) 1,810,194 1,815,843
Current Liabilities: Preferred Stock Redemption Requirement 12,250 12,250 Long Term Debt 1,000 - Short Term Debt 8,600 - Accounts Payable 66,080 63,847 Taxes Accrued 10,409 16,020 Interest Accrued 19,168 22,149 Dividends Declared 24,681 24,910 Accrued Employee Separation Costs 26,600 - Other 19,813 25,626 Total Current Liabilities 188,601 164,802
Deferred Credits and Other Liabilities: Deferred Income Taxes 412,574 383,347 Deferred Investment Tax Credits 51,646 54,180 Capital Lease Obligations 41,111 44,407 Other 41,429 24,929 Total Deferred Credits and Other Liabilities 546,760 506,863
Commitments and Contingencies (Note 10)
Total Liabilities and Capitalization $2,545,555 $2,487,508
CONSOLIDATED STATEMENT OF CHANGES IN Atlantic Energy, Inc. COMMON SHAREHOLDERS' EQUITY and Subsidiaries (Thousands of Dollars) Common Retained Shares Stock Earnings
Balance, December 31, 1991 50,896,074 $520,345 $234,894 Common Stock issued 1,302,550 28,802 Net Income 86,210 Common stock dividends (78,336) Balance, December 31, 1992 52,198,624 549,147 242,768 Common Stock issued 1,308,162 30,296 Net Income 95,297 Capital stock expense of subsidiary (169) Common stock dividends (81,347) Balance, December 31, 1993 53,506,786 579,443 256,549 Common Stock issued 870,159 17,941 Common Stock repurchased (221,700) (3,909) Net Income 76,113 Common stock dividends (83,481) Balance, December 31, 1994 54,155,245 $593,475 $249,181
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.
Notes to Consolidated Financial Statements Note 1. SIGNIFICANT ACCOUNTING POLICIES
Organization - Atlantic Energy, Inc. (the Company, AEI or parent) is the parent of a consolidated group of wholly-owned subsidiaries consisting of: Atlantic City Electric Company (ACE) and the following nonutility companies: Atlantic Energy Technology, Inc. (AET), Atlantic Generation, Inc. (AGI), Atlantic Southern Properties, Inc. (ASP), ATE Investment, Inc. (ATE) and Atlantic Thermal Systems, Inc. (ATS). ACE is a public utility primarily engaged in the generation, transmission, distribution and sale of electric energy. Rates for service are regulated by the New Jersey Board of Public Utilities (BPU), formerly Board of Regulatory Commissioners. ACE's service territory encompasses approximately 2,700 square miles within the southern one-third of New Jersey. The majority of ACE's customers are residential and commercial. ACE, with its wholly-owned subsidiary that operates certain generating facilities, is the principal subsidiary within the consolidated group. AGI and its wholly-owned subsidiaries are engaged in the development and operation of cogeneration power projects, currently located in New Jersey and New York through several partnership arrangements. ASP owns and manages a commercial office and warehouse facility located in southern New Jersey. ATE provides fund management and financing to affiliates and manages a portfolio of investments in leveraged leases for equipment used in the airline and shipping industries. ATS and its wholly-owned subsidiary, both formed in May 1994, are engaged in the development of thermal heating and cooling systems. AET is presently concluding the affairs of its subsidiary, which is its sole investment. On January 1, 1995, a new subsidiary of AEI, Atlantic Energy Enterprises, Inc. (AEE), was formed. AEI will transfer direct ownership of the existing nonutility companies to AEE. AEE will seek to form new businesses and ventures and invest in established businesses.
Principles of Consolidation - The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. ACE, AET, AGI and ATS consolidate their respective subsidiaries. AGI accounts for another investment using the equity method by recognizing its proportionate share of the results of operations of that investment. The results of operations of the nonutility companies are not significant to the results of the Company and are classified under Other Income in the Consolidated Statement of Income.
Regulation - The accounting policies and rates of ACE are subject to the regulations of the BPU and in certain respects to the Federal Energy Regulatory Commission (FERC). ACE follows generally accepted accounting principles (GAAP) and financial reporting requirements employed by all industries as specified by the Financial Accounting Standards Board (FASB) and the Securities and Exchange Commission (SEC). However, accounting for rate regulated industries may depart from GAAP applied by other industries as permitted by Statement of Financial Accounting Standards No. 71 (SFAS No. 71). SFAS No. 71 provides guidance on circumstances where the economic effect of a regulator's decision warrants different applications of GAAP as a result of the rate making process. In setting rates, a regulator may provide recovery of an incurred cost in a year or years other than the year the cost is incurred. As permitted by SFAS No. 71, costs ordered by a regulator to be deferred or capitalized for future recovery are recorded as a regulatory asset because the regulator's rate action provides reasonable assurance of future economic benefits attributable to these costs. In a non-rate regulated industry, such costs may be charged to expense in the year incurred. SFAS No. 71 further specifies that a regulatory liability is recorded when a regulator orders a refund to customers of revenues previously collected, or when existing rates provide for recovery of future costs not yet incurred. Such treatment is not afforded to non-rate regulated companies. When collection of regulatory assets or relief of regulatory liabilities is no longer probable, the assets and liabilities are applied to income in the year that the probability assessment is made. Specific regulatory assets and liabilities that have been recorded are discussed elsewhere in the notes to the consolidated financial statements.
Electric Operating Revenues - Revenues are recognized when electric energy services are rendered, and include estimates for amounts unbilled at the end of the period for energy used subsequent to the last billing cycle.
Nuclear Fuel - Fuel costs associated with ACE's participation in jointly-owned nuclear generating stations, including spent nuclear fuel disposal costs, are charged to Energy expense based on the units of thermal energy produced.
Electric Utility Plant - Property is stated at original cost. Generally, the plant is subject to a first mortgage lien. The cost of property additions, including replacement of units of property and betterments, is capitalized. Included in certain property additions is an Allowance for Funds Used During Construction (AFDC), which is defined in the applicable regulatory system of accounts as the cost during the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used. AFDC has been calculated using a semi-annually compounded rate of 8.25%, as approved by the BPU, since August 1, 1993. The AFDC rate was 8.95%, as approved by the BPU, prior to this date.
Depreciation - ACE provides for straight-line depreciation based on the estimated remaining life of transmission and distribution property, remaining life of the related nuclear plant operating license for nuclear property and estimated average service life for all other depreciable property. The overall composite rate of depreciation was approximately 3.3% in 1994 and 1993 and 3.5% in 1992. Accumulated depreciation is charged with the cost of depreciable property retired together with removal costs less salvage and other recoveries. Depreciation expense for the nonutility companies is not significant.
Nuclear Decommissioning Trust - ACE has a trust to fund the future costs of decommissioning each of the five nuclear units in which it has an ownership interest. The current annual funding amount, as authorized by the BPU, totals $6.4 million and is provided for in rates charged to customers. The funding amount is based on estimates of the future cost of decommissioning each of the units, dates that decommissioning activities are expected to occur and return to be earned by the assets of the fund. The present value of ACE's nuclear decommissioning obligation, based on 1987 site specific studies used by the BPU for approval in 1991 and restated in 1994 dollars, is $152.2 million. The BPU has further established that decommissioning activities are expected to begin in 2006 and continue through 2032. Actual costs and timing of decommissioning activities may vary from the current estimates. ACE will seek to adjust these estimates and the level of rates collected from customers in future BPU proceedings to reflect changes in decommissioning cost estimates and the expected levels of inflation and interest to be earned by the assets in the trust. As of December 31, 1994, the present value of such contributions based on estimates for future decommissioning costs and the dates such activities are expected to occur is $111.4 million, without earnings on or appreciation of the fund assets. As of December 31, 1994, the cost and market value of the trust were $52 million. Trust contributions of the related $36.9 million qualify for Federal income tax purposes. The related reserve for decommissioning costs are presented as a component of accumulated depreciation and amount to $51.1 million at December 31, 1994 and $42.2 million at December 31, 1993.
The SEC has questioned certain accounting practices employed by the electric utility industry concerning decommissioning costs for nuclear generating facilities. The FASB is currently reviewing this issue within the broad context of removal costs relative to all industries. At this time, the Company cannot predict what future accounting practices may be required by the FASB and SEC concerning this issue, nor the impact on the financial statements that any new accounting practices may have.
Deferred Energy Costs - As approved by the BPU, ACE has a Levelized Energy Clause (LEC) through which energy and energy- related costs (energy) are charged to customers. LEC rates are based on projected energy costs and prior period underrecoveries or overrecoveries of energy costs. Energy costs are recovered through levelized rates over the period of projection, which is generally a 12-month period. In any period, the actual amount of LEC revenues recovered from customers may be greater or less than the recoverable amount of actual energy costs incurred in that period. Energy expense is adjusted to match the associated LEC revenues. Any underrecovery (an asset representing energy costs incurred that are to be collected from customers) or overrecovery (a liability representing previously collected energy costs to be returned to customers) of costs is deferred on the Consolidated Balance Sheet as Deferred Energy Costs. These deferrals are recognized in the Consolidated Statement of Income as Energy expense during the period in which they are subsequently included in the LEC.
Income Taxes - Effective January 1, 1993, deferred Federal and state income taxes are provided on all significant temporary differences between book bases and tax bases of assets and liabilities, transactions that reflect taxable income in a year different than book income, and tax carryforwards. Deferred Federal and state income taxes for 1992 were provided on all significant current transactions for which the timing of recognition differs for book and tax purposes. Investment tax credits, which are used to reduce current Federal income taxes, are deferred on the Consolidated Balance Sheet and recognized in book income over the life of the related property. The Company and its subsidiaries file a consolidated Federal income tax return. Income taxes are allocated to each of the companies within the consolidated group based on the separate return method.
Earnings Per Common Share - This is computed based upon the weighted average number of common shares outstanding during the year. Common stock equivalents attributable to the Equity Incentive Plan do not impact this computation because they are currently antidilutive.
Unrecovered Purchased Power Costs - ACE has an arrangement that commenced in 1983 to purchase capacity and related energy through September 30, 2000. Levelized base rates over the term of the arrangement were approved by the BPU to recover costs estimated at commencement to be incurred. During the first half of the term, estimated costs that exceeded levelized revenues were deferred on the Consolidated Balance Sheet as Unrecovered Purchased Power Costs. Since then, levelized revenues have been greater than the estimated costs, permitting the deferred costs to be charged to Purchased Capacity expense on the Consolidated Statement of Income. The BPU granted a return on the unrecovered deferred balance throughout the term of the arrangement. The unrecovered deferred balances at December 31, 1994 and 1993 were $95.9 million and $110.5 million, respectively. Also included within Unrecovered Purchased Power Costs are costs incurred in renegotiating a contract with an independent power producer. These costs are amortized to expense over the BPU-approved recovery period of 20 years beginning in 1994. The unrecovered balances were $19.6 million and $20 million at December 31, 1994, respectively.
Regulatory Assets and Liabilities - Costs incurred by ACE that have been permitted by the BPU to be deferred for recovery in rates in more than one year, or for which future recovery is probable, have been recorded as regulatory assets. Regulatory assets are amortized to expense over the period of recovery. Total regulatory assets on the Consolidated Balance Sheet at December 31, 1994 and 1993 were $365.5 million and $332.1 million, respectively. Unamortized costs currently being recovered in rates at December 31, 1994 and 1993, respectively, and remaining recovery periods at December 31, 1994 are: Unrecovered State Excise Taxes of $73.8 million and $33.7 million, with a remaining recovery period of eight years; decommissioning and decontaminating Federally-owned nuclear units of $7.2 million and $8.4 million, with a remaining recovery period of 14 years; and asbestos removal of $9.6 million and $9.9 million for which the recovery period is over the remaining depreciable life of the related generating station of 36 years. Property Abandonment Costs at their net present value of $5 million and $6.3 million at December 31, 1994 and 1993, respectively, are being recovered through rates with no return on the unamortized balances of $6.5 million and $8.5 million, respectively. Such costs were written down to their net present values at the date of abandonment with subsequent accretions of the unamortized balances over the recovery period. These costs have a recovery period between two and seven years. Also included in Other Regulatory Assets are amounts for which future recovery is probable of $9.4 million and $9.1 million at December 31, 1994 and 1993, respectively. Costs associated with debt reacquired by refundings, included in Unamortized Debt Costs, are amortized over the life of the newly issued debt as permitted by the BPU in accordance with FERC guidelines. The unamortized balances of these costs were $32.2 million and $33.2 million at December 31, 1994 and 1993, respectively. Recovery of regulatory assets for Unrecovered Purchased Power Costs (Note 1), Deferred Energy Costs (Note 1), Recoverable Future Federal Income Taxes (Note 2) and Postretirement Benefits Other Than Pensions (Note 4) are separately discussed in the Notes to Consolidated Financial Statements where indicated. No regulatory liabilities existed at December 31, 1994 and 1993.
Financial Instruments - A number of items within Current Assets and Current Liabilities on the Consolidated Balance Sheet are considered to be financial instruments because they are cash or are to be settled in cash. Due to their short term nature, the carrying values of these items approximate their fair market values. Accounts Receivable - Utility Service and Unbilled Revenues are subject to concentration of credit risk because they pertain to utility service conducted within a confined geographic region. Investments in Leveraged Leases are subject to concentration of credit risk because they are exclusive to a small number of parties within two industries. The Company has recourse to the affected assets under lease. These leased assets are of general use within their respective industries.
Other - Debt premium, discount and expenses of ACE are amortized over the life of the related debt. Temporary investments considered as cash equivalents for Consolidated Statement of Cash Flows purposes represent purchases of highly liquid debt instruments maturing in three months or less. The weighted daily average interest rates on short term debt was 4.4% for 1994 and 3.2% for 1993.
Certain prior year amounts have been reclassified to conform to the current year reporting of these items. NOTE 2. INCOME TAXES
For the Years Ended December 31, (000) 1994 1993 1992
The components of Federal income tax expense are as follows: Current $ 19,729 $ 25,349 $ 22,441 Deferred 17,414 20,247 23,154 Investment Tax Credits Recognized on Leveraged Leases - (12) (233) Total Federal Income Tax Expense 37,143 45,584 45,362 Less Amounts Included in Other Income (5,386) 307 8,219 Federal Income Taxes Included in Operating Expenses $ 42,529 $ 45,277 $ 37,143
A reconciliation of the expected Federal income taxes compared to the reported Federal income tax expense computed by applying the statutory rate follows:
Statutory Federal Income Tax Rate 35% 35% 34%
Income Tax Computed at the Statutory Rate $ 45,490 $ 55,400 $ 50,791 Plant Basis Differences (27) (5,171) 2,022 Amortization of Investment Tax Credits (2,534) (2,546) (2,767) Tax Adjustments (4,097) (2,071) (3,757) Other-Net (1,689) (28) (927) Total Federal Income Tax Expense $ 37,143 $ 45,584 $ 45,362
Effective Federal Income Tax Rate 29% 29% 30%
State income tax expense is not significant.
Items comprising deferred tax balances are as follows at December 31, 1994 and 1993: (000) 1994 1993 Deferred Tax Liabilities: Plant Basis Differences $304,476 $295,445 Leveraged Leases 61,409 53,461 Unrecovered Purchased Power Costs 33,557 38,792 State Excise Taxes 25,842 11,797 Other 24,732 21,057 Total Deferred Tax Liabilities 450,016 420,552 Deferred Tax Assets: Deferred Investment Tax Credits 27,879 29,247 Employee Separation Costs 6,932 - Other 15,245 11,741 Total Deferred Tax Assets 50,056 40,988 Total Deferred Taxes-Net $399,960 $379,564
At December 31, 1994 and 1993, valuation allowances exist against deferred tax assets primarily for cumulative net operating losses (NOLs) for state income tax purposes. The effects of the valuation allowances and state NOLs are generally not material to consolidated results of operation and financial position.
The Company is subject to Federal Alternative Minimum Tax (AMT), which is attributable to nonutility operations. At December 31, 1994, there is an estimated cumulative AMT credit of $12.5 million. The AMT credit is available for an indefinite carryforward period against future Federal income tax payable, to the extent that the regular Federal income tax payable exceeds future AMT payable.
Deferred tax costs associated with additional deferred tax liabilities resulting from a change in accounting standards regarding deferred taxes effective in 1993 are recorded on the Consolidated Balance Sheet as Recoverable Future Federal Income Taxes. Such recognition is given in respect of the probable amount of revenue to be collected from ratepayers for these additional taxes to be paid in future years.
NOTE 3: RATE MATTERS OF ACE
Energy Clause Proceedings
Changes in Levelized Energy Clause Rates 1992 - 1994
Amount Amount Date Requested Granted Date Filed (millions) (millions) Effective
2/92 $(6.6) $(8.5) 10/92 3/93 14.2 10.9 10/93 2/94 63.0 55.0 7/94
ACE's Levelized Energy Clause (LEC) is subject to annual review by the BRC.
In February 1992, ACE filed a petition with the BPU for the LEC period June 1, 1992 through May 31, 1993 requesting no change in LEC rates. In April 1992, ACE filed a revision to their petition requesting a $6.6 million decrease in LEC rates based on an update for the projected overrecovery of prior LEC costs and an amount allocated to customers from the litigation settlement with PECO Energy (PECO) related to the Peach Bottom Atomic Power Station. In October 1992, the BPU approved a reduction in annual LEC revenues of $8.5 million which included the recovery of $10.4 million over a three-year period of certain deferred costs relating to the Salem Nuclear Generating Station. The PECO settlement allocation was subject to review by the BPU in ACE's 1993 LEC proceeding.
In March 1993, ACE filed a petition with the BPU requesting a $14.2 million increase in LEC revenues for the June 1, 1993 through May 31, 1994 LEC period. Effective for service rendered on and after October 1, 1993, the BPU approved an increase of $10.9 million which included the following: 1) an additional $3.8 million of the PECO settlement together with accrued interest to be returned to customers during the 1994-1995 LEC period; 2) recovery of $400 thousand for the annual assessment for the Department of Energy (DOE) decommissioning and decontamination fund; 3) full LEC recovery of all future assessments for the DOE decommissioning and decontamination fund and 4) recognition of the $48 thousand penalty for 1992 nuclear operations as required by the Nuclear Performance Standard. The additional allocation of the PECO settlement was provided for in the 1993 financial results and the reimbursement was made through the 1994 LEC.
On February 8, 1994, ACE filed a petition with the BPU requesting an increase in LEC revenues of $63 million for the period June 1, 1994 through May 31, 1995. The increase was due primarily to the additional costs incurred from two new independent power producers (IPPs) scheduled to begin commercial operation during the 1994/1995 LEC period. The total projected costs for fuel and capacity for the LEC period were $147 million. ACE reduced the requested amount by $84 million as a result of the utilization of $56 million of current base rate revenues associated with a utility power purchase contract expiring in May 1994 and the Southern New Jersey Economic Initiative (SNJEI), an ACE initiative that forgoes the recovery of $28 million of fuel costs. Included in ACE's request was the recovery over five years of $20 million paid by ACE in December 1993 in connection with contract renegotiations with an IPP. Effective July 26, 1994, the BPU approved a provisional increase of $55 million based on an adjustment to actual costs for fuel and capacity. On November 30, 1994, the BPU rendered its decision on ACE's LEC request approving the continuation of provisional LEC rates, the recovery of the $20 million in renegotiation costs and the reduction for the $28 million SNJEI.
Base Rate Case Proceedings
Effective October 1992, the BPU authorized a net increase in annual base rate revenues of $12.9 million. In March 1994, in response to an appeal filed by the Ratepayer Advocate in December 1992, the Superior Court of New Jersey, Appellate Division, affirmed the BPU's decision to allow an increase in base rates relating to changes in the state excise tax.
Other Rate Proceedings
In November 1993, ACE filed a petition with the BPU requesting that hotel-casino customers be permitted to take service under rate schedules offered to all other commercial and industrial customers. On June 23, 1994, the BPU approved the request with a provision that ACE not seek recovery of lost revenues resulting from the hotel-casinos being permitted to shift to other rate schedules prior to ACE's next base rate case. The BPU also allowed for a one-time adjustment to be billed to hotel-casino customers for the associated underrecovery in ACE's fuel clause. Prior to BPU approval, hotel-casino customers were served under the Hotel Casino Service rate schedule, the highest rate for service of all ACE's service classes. Effective July 1, 1994, all hotel-casino customers began taking service under a general service rate schedule which could reduce annual base rate revenues by approximately $7 million. Effective July 25, 1994, the Hotel Casino Service rate schedules were no longer offered for electric service.
In July 1993, the BPU initiated a generic proceeding to address the recovery of the capacity costs associated with purchases of power from nonutility generation projects. This issue relates to the Ratepayer Advocate's contention that present BPU policy which permits full recovery of these costs through the LEC provides for a "double recovery" of cogeneration capacity costs. In August 1993, the Ratepayer Advocate identified ACE as one of the electric utilities for which they considered the double recovery of capacity costs to be at issue. Pursuant to its February 18, 1994 decision supporting the investigation of the double recovery of capacity costs from nonutility generation projects, the BPU issued its written order on September 16, 1994. The order confirmed the establishment of a generic proceeding to review the nonutility purchase power capacity cost recovery methodology and ordered that the matter be reviewed in a two phase proceeding. The scope of the issues to be resolved during the first phase of the proceeding will include: 1) the determination of the existence, or lack of existence, of the double recovery as a result of the traditional LEC pass-through of nonutility generation capacity costs; 2) the quantification of any such double recovery found to exist for each utility for the relevant periods; and 3) a determination of an appropriate remedy or adjustment if such double recovery is found to occur and the periods of time over which such an adjustment would be applicable. Following the conclusion of the first phase of the proceeding, the BPU, in the second phase, will render a final decision regarding the specific findings of the Office of Administrative Law and address the broader issues relating to the appropriate prospective purchase power capacity cost recovery methods. Evidentiary hearings have been scheduled through December 1995. The BPU's final decision is not anticipated until 1996. At this time, ACE cannot predict the outcome of this proceeding and cannot estimate the impact that the double recovery issue may have on future rates.
NOTE 4. RETIREMENT BENEFITS Pension
ACE has a noncontributory defined benefit pension plan covering substantially all of its employees and those of its wholly-owned subsidiary. Benefits are based on an employee's years of service and average final pay. ACE's policy is to fund pension costs within the guidelines of the minimum required by the Employee Retirement Income Security Act and the maximum allowable as a tax deduction. Each company is allocated its participative share of plan costs and contributions.
Net periodic pension costs for 1994, 1993 and 1992 included the following components: (000) 1994 1993 1992
Service cost - benefits earned during the period $ 6,871 $ 7,196 $ 7,310 Interest cost on projected benefit obligation 15,390 16,016 17,301 Actual return on plan assets (860) (23,200) (13,283) Other-net (16,885) 5,496 (3,795) Net periodic pension costs $ 4,516 $ 5,508 $ 7,533
Approximately $3 million, $5.2 million and $4.8 million of these costs were charged to operating expense in 1994, 1993 and 1992, respectively, and the remaining costs, which are associated with construction labor, were charged to the cost of new utility plant.
A reconciliation of the funded status of the plan as of December 31, 1994 and 1993 is as follows: (000) 1994 1993 Fair value of plan assets $190,200 $213,600 Projected benefit obligation 206,742 207,246 Plan assets (less than) in excess of projected benefit obligation (16,542) 6,354 Unrecognized net transition asset (1,722) (1,894) Unrecognized prior service cost 306 329 Unrecognized net loss (gain) 24,106 (638) Prepaid pension cost $ 6,148 $ 4,151 Accumulated benefit obligation: Vested benefits $166,602 $165,872 Nonvested benefits 485 1,216 Total $167,087 $167,088
At December 31, 1994, approximately 60% of plan assets were invested in equity securities, 18% in fixed income securities and 22% in other investments. The assumed rates used in determining the actuarial present value of the projected benefit obligation at year-end were as follows: 1994 1993 Weighted average discount 7.5% 7.5% Anticipated increase in compensation 3.5% 3.5%
The assumed long term rate of return on plan assets was 8.5% for both 1994 and 1993 and 8% for 1992.
Other Postretirement Benefits
ACE and its subsidiary provide certain health care and life insurance benefits for retired employees and their eligible dependents. Substantially all employees may become eligible for these benefits if they reach retirement age while working for the companies. Benefits are provided through insurance companies and other plan providers whose premiums and related plan costs are based on the benefits paid during the year. ACE has a tax qualified trust to fund these benefits. Each company is allocated its participative share of plan costs and contributions.
The cost of other postretirement benefits was $15.6 million, $13.1 million and $6 million in 1994, 1993 and 1992, respectively. These costs were allocated as follows:
(millions) 1994 1993 1992 Operating expense $5.6 $3.3 $3.8 New utility plant-associated with construction labor .2 1.7 2.2 Regulatory asset 9.8 8.1 -
The regulatory assets represent the amount of cost recognized under accounting standards effective January 1, 1993 in excess of the amount of cost currently recovered in rates. These excess costs are deferred as authorized by an accounting order of the BPU pending future recovery through rates.
Net periodic other postretirement benefits cost as calculated in accordance with accounting standards in effect since January 1, 1993 include: 1994 1993 (000) Service cost-benefits attributed to service during the period $ 3,817 $ 3,045 Interest cost on accumulated postretirement benefits obligation 8,450 7,133 Actual return on plan assets 100 (255) Amortization of unrecognized transition obligation 3,893 3,893 Other-net (700) (711) Net periodic other postretirement cost $15,560 $13,105
A reconciliation of the funded status of the plan and the obligation for other postretirement benefits recognized in the Consolidated Balance Sheet as of December 31, 1994 and 1993 is as follows:
(000) 1994 1993 Accumulated benefits obligation: Retirees $ 43,265 $ 32,720 Fully eligible active plan participants 18,010 21,267 Other active plan participants 60,588 49,125 Total accumulated benefits obligation 121,863 103,112 Less fair value of plan assets 14,700 14,400 Accumulated benefits obligation in excess of plan assets 107,163 88,712 Unrecognized net loss (19,223) (6,639) Unamortized unrecognized transition obligation (70,075) (73,968) Accrued other postretirement benefits cost obligation $ 17,865 $ 8,105
At December 31, 1994, approximately 81% of plan assets were invested in fixed income securities and 19% in other investments.
The assumed health care costs trend rate for 1994 is 10% and is assumed to evenly decline to an ultimate constant rate of 5% in the year 2000 and thereafter. If the assumed health care costs trend rate was increased by 1% in each future year, the aggregate service and interest costs of the 1994 net periodic benefits cost would increase by $1.9 million, and the accumulated postretirement benefits obligation at December 31, 1994 would increase by $16.7 million. The weighted average discount rate assumed in determining the accumulated benefits obligation was 7.5% for 1994 and 1993. The assumed long term return rate on plan assets was 7% for 1994 and 1993.
NOTE 5. JOINTLY-OWNED GENERATING STATIONS
ACE owns jointly with other utilities several electric production facilities. ACE is responsible for its pro-rata share of the costs of construction, operation and maintenance of each facility.
The amounts shown represent ACE's share of each facility at, or for the year ending, December 31, including AFDC as appropriate. Peach Hope Keystone Conemaugh Bottom Salem Creek Energy Source Coal Coal Nuclear Nuclear Nuclear Company's Share (%/MWs) 2.47/42.3 3.83/65.4 7.51/157.0 7.41/164.0 5.00/52.0
Electric Plant in Service (000): 1994 $11,293 $26,607 $125,003 $206,804 $238,980 1993 10,746 18,055 123,428 203,858 237,496
Accumulated Depreciation (000): 1994 $3,180 $6,237 $55,190 $79,898 $53,746 1993 3,231 5,971 51,871 78,383 46,933
Construction Work in Progress (000): 1994 $1,216 $2,649 $11,002 $ 8,727 $ 387 1993 758 9,956 7,983 10,799 1,022
Working Funds (000): 1994 $44 $69 $5,051 $5,199 $2,013 1993 44 69 4,772 5,249 2,061
Operation and Maintenance Expenses (including fuel)(000): 1994 $5,085 $7,211 $29,530 $27,731 $10,471 1993 5,323 6,855 31,479 27,021 9,764 1992 4,976 7,194 29,618 25,461 9,541
Generation (MWH): 1994 257,561 419,313 1,214,776 836,725 355,390 1993 293,876 416,263 1,043,485 840,043 440,118 1992 294,222 457,771 958,740 737,356 351,672
ACE provides financing during the construction period for its share of the jointly-owned facilities and includes its share of direct operations and maintenance expenses in the Consolidated Statement of Income. Additionally, ACE provides an amount of working funds to the operators of the facilities to fund operational needs. The increase in Electric Plant in Service and decrease in Construction Work in Progress for Conemaugh is primarily due to the placement in service of flue gas disulfurization equipment (scrubber).
NOTE 6. NONUTILITY COMPANIES
The Company (AEI) is the parent holding company of the consolidated group. Its primary activities are the management of investments in the subsidiary companies, issuance of common equity and performance of administrative functions on behalf of the consolidated group. Principal assets of each of the subsidiary companies are: AGI - capital investments of approximately $30.3 million in cogeneration development projects and partnerships; ASP - commercial real estate site with a net book value of $10.3 million; ATE - leveraged lease investments of $78.2; million and ATS - construction costs in thermal heating and cooling projects of $6.3 million. AET is presently concluding the affairs of its subsidiary, which is its sole investment. The net investment in this subsidiary is nominal.
Other financial information regarding the subsidiary companies is as follows:
Net Assets Net Income (Loss) Company 1994 1993 1994 1993 1992 (000) AGI $23,610 $18,746 $2,959 $4,459 $ 1,366 ASP 3,175 5,131 (1,956) (347) (263) ATE 9,449 9,182 266 (777) 667 ATS 2,577 - (327) - - AET 1,324 2,069 (744) 524 (4,793)
AGI's results reflect the operation of cogeneration facilities in which AGI has an ownership interest. AGI's 1994 results were reduced by decreased operation of a cogeneration unit and an increase in deferred income tax expenses.
ASP's results in each year reflect the vacancy in its commercial site due to generally poor market conditions in commercial real estate. The 1994 results include a net after tax write-down of the carrying value of the commercial site of $1.7 million.
ATE's 1994 results reflect a reduction in deferred income tax expense. ATE's 1993 results were reduced by increased deferred state income tax expense. ATE's 1992 results benefitted from lower interest rates on amounts outstanding under its revolving credit agreement.
ATS, formed in May 1994, is primarily a developmental stage company that will become operational as heating and cooling system projects are completed. The 1994 results reflect administrative and general costs.
AET's 1994 results reflect expenses incurred researching future investment opportunities and an increase in deferred Federal income tax expense. AET's 1993 results are due to the receipt of life insurance proceeds by its subsidiary company. In 1993, this subsidiary discontinued its operating activities to concentrate on licensing its patented proprietary knowledge. AET's 1992 results reflect the provision for the restructuring of its subsidiary's activities.
AEI parent-only operations, excluding its equity in the results of subsidiary companies, generally reflect administrative expenses. Net results were losses of $543 thousand in 1994, $183 thousand in 1993 and $401 thousand in 1992.
NOTE 7. CUMULATIVE PREFERRED STOCK OF ACE
ACE has authorized 799,979 shares of Cumulative Preferred Stock, $100 Par Value, two million shares of No Par Preferred Stock and three million shares of Preference Stock, No Par Value. Information relating to outstanding shares at December 31 is shown in the table below. Current Optional 1994 1993 Redemption Series Par Value Shares (000) Shares (000) Price
Not Subject to Mandatory Redemption: 4% $100 77,000 $ 7,700 77,000 $ 7,700 $105.50 4.10% 100 72,000 7,200 72,000 7,200 101.00 4.35% 100 15,000 1,500 15,000 1,500 101.00 4.35% 100 36,000 3,600 36,000 3,600 101.00 4.75% 100 50,000 5,000 50,000 5,000 101.00 5% 100 50,000 5,000 50,000 5,000 100.00 7.52% 100 100,000 10,000 100,000 10,000 101.88 Total $40,000 $40,000
Subject to Mandatory Redemption: $8.25 None 55,000 $ 5,500 60,000 $ 6,000 104.66 $8.53 None 360,000 36,000 600,000 60,000 102.00 $8.20 None 500,000 50,000 500,000 50,000 - $7.80 None 700,000 70,000 700,000 70,00 - Total 161,500 186,000 Less portion due within one year 12,250 12,250 Total $149,250 $173,750
Cumulative Preferred Stock Not Subject to Mandatory Redemption is redeemable solely at the option of ACE.
On November 1 of each year, 2,500 shares of the $8.25 No Par Preferred Stock must be redeemed through the operation of a sinking fund at a redemption price of $100 per share. ACE may redeem not more than an additional 2,500 shares on any sinking fund date without premium. ACE redeemed 5,000 shares in both 1994 and 1993.
Commencing in 1994, on November 1 of each year, 120,000 shares of the $8.53 No Par Preferred Stock must be redeemed through the operation of a sinking fund at a redemption price of $100 per share. At the option of ACE, not more than an additional 120,000 shares may be redeemed on any sinking fund date without premium. ACE redeemed 240,000 shares in 1994.
Beginning August 1, 1996 and annually thereafter, 100,000 shares of the $8.20 No Par Preferred Stock must be redeemed through the operation of a sinking fund at a redemption price of $100 per share. At the option of ACE, not more than an additional 100,000 shares may be redeemed on any sinking fund date without premium. This series is not refundable prior to August 1, 2000.
Beginning May 1, 2001 and annually through 2005, 115,000 shares of $7.80 No Par Preferred Stock must be redeemed through the operation of a sinking fund at a redemption price of $100 per share. On May 1, 2006, the remaining shares outstanding must be redeemed at $100 per share. ACE has the option to redeem up to an additional 115,000 shares without premium on each May 1 through 2005. This series is not refundable prior to May 1, 2006.
For the next five years, the annual minimum sinking fund requirements of the Cumulative Preferred Stock Subject to Mandatory Redemption is $12.25 million for the year 1995, and $22.25 million in each of the years 1996 and 1997 and $10.25 million in each of the years 1998 and 1999.
Cumulative Preferred Stock of ACE is not widely held and trades infrequently. The estimated aggregate fair market value of ACE's outstanding Cumulative Preferred Stock at December 31, 1994 and 1993 was approximately $185 million and $231 million, respectively. The fair market value has been determined using market information available from actual trades of similar instruments of companies with similar credit quality and rate.
NOTE 8. LONG TERM DEBT Maturity December 31 Series Date 1994 1993
(Medium Term Notes (MTNs) have varying maturity dates and are shown with the weighted average interest rate of the related issues within the year of maturity.) (000) 5-1/8% First Mortgage Bonds 2/1/1996 $ 9,980 $ 9,980 Medium Term Notes Series B (6.28%) 1998 56,000 56,000 Medium Term Notes Series A (7.52%) 1999 30,000 30,000 Medium Term Notes Series B (6.83%) 2000 46,000 46,000 7-1/2% First Mortgage Bonds 4/1/2002 20,000 20,000 Medium Term Notes Series B (7.18%) 2003 20,000 20,000 7-3/4% First Mortgage Bonds 6/1/2003 29,976 29,976 Medium Term Notes Series A (7.98%) 2004 30,000 30,000 Medium Term Notes Series B (7.125%) 2004 28,000 28,000 7-5/8% Pollution Control 1/1/2005 - 6,500 Medium Term Notes Series B (6.45%) 2005 40,000 40,000 6-3/8% Pollution Control 12/1/2006 2,500 2,500 Medium Term Notes Series B (6.76%) 2008 50,000 50,000 10-1/2% Pollution Control Series B 7/15/2012 850 850 6-5/8% First Mortgage Bonds 8/1/2013 75,000 75,000 7-3/8% Pollution Control Series A 4/15/2014 18,200 18,200 10-1/2% Pollution Control Series C 7/15/2014 - 23,150 8-1/4% Pollution Control Series A 7/15/2017 4,400 4,400 9-1/4% First Mortgage Bonds 10/1/2019 53,857 65,767 6.80% Pollution Control Series A 3/1/2021 38,865 38,865 7% First Mortgage Bonds 9/1/2023 75,000 75,000 5.60% Pollution Control Series A 11/1/2025 4,000 4,000 7% First Mortgage Bonds 8/1/2028 75,000 75,000 6.15% Pollution Control Series A 6/1/2029 23,150 - 7.20% Pollution Control Series A 11/1/2029 25,000 - 7% Pollution Control Series B 11/1/2029 6,500 - Total 762,278 749,188 Debentures: 5-1/4% 2/1/1996 2,267 2,267 7-1/4% 5/1/1998 2,619 2,619 Total 4,886 4,886 Unamortized Premium and Discount-Net (3,876) (2,973) Total Long Term Debt of ACE 763,288 751,101 Long Term Debt of ATE 16,000 15,000 Less Portion Due within One Year 1,000 - $778,288 $766,101
In 1994, ACE redeemed its 10-1/2% Pollution Control Bonds Series C due 7/15/2014 and its 7-5/8% Pollution Control Bonds due 1/1/2005. ACE acquired and retired $11.9 million principal amount of First Mortgage Bonds, 9-1/4% Series due 10/1/2019. The aggregate cost of these redemptions was $1.2 million, net of related Federal income taxes.
Sinking fund deposits are required for retirement of the 5-1/4% Debentures annually on February 1 through 1995 and for the 7-1/4% Debentures annually on May 1 through 1997 in amounts in each case sufficient to redeem $100,000 principal amount. ACE may, at its option, redeem an additional $100,000 annually in each case. Through December 31, 1994, ACE acquired and cancelled $333 thousand and $181 thousand principal amount of the 5-1/4% and 7-1/4% Debentures, respectively, which will be used to satisfy its requirements for 1995. Certain series of First Mortgage Bonds contain provisions for deposits of cash or certification of bondable property currently amounting to $100 thousand, which ACE may elect to satisfy through property additions. For the next five years, the annual amount of scheduled maturities and sinking fund requirements of ACE's long term debt are $12.266 million in 1996, $175 thousand in 1997, $58.575 million in 1998 and $30.075 million in 1999.
ACE's long term debt securities are not widely held and generally trade infrequently. The estimated aggregate fair market value of ACE's outstanding long term debt at December 31, 1994 and 1993 was $693 million and $768 million, respectively. The fair market value has been determined based on quoted market prices for the same or similar debt issues or on debt instruments of companies with similar credit quality, coupon rates and maturities.
Long term debt of ATE primarily consists of $15 million of 7.44% Senior Notes due 1999.The estimated fair market value of these Notes at December 31, 1994 and 1993 was $14 million and $16 million, respectively, based on debt instruments of companies with similar credit quality, coupon rates and maturities. Also, ATE has a revolving credit and term loan agreement which provides for borrowings of up to $35 million during successive revolving credit and term loan periods through June 1995. There were $1 million in borrowings outstanding under this agreement at December 31, 1994. Commitment fees on the unused credit line were not significant.
NOTE 9. COMMON SHAREHOLDERS' EQUITY
In addition to public offerings, Common Stock may be issued through the Dividend Reinvestment and Stock Purchase Plan (DRP), ACE benefit plans (ACE plans) and the Equity Incentive Plan (EIP). The number of shares of Common Stock issued (forfeited), and the number of shares reserved for issuance at December 31, 1994, were as follows:
1994 1993 1992 Reserved DRP 699,493 1,300,129 1,291,653 723,975 ACE Plans (5,046) 8,033 10,897 141,038 EIP 175,712 - - 624,288 Total 870,159 1,308,162 1,302,550
In April 1994, the shareholders of the Company approved the EIP. Eligible participants are officers, general managers and nonemployee directors of the Company and its subsidiaries. Under the EIP, nonemployee director participants are entitled to receive a grant of 1,000 shares of restricted stock. Restrictions on these grants expire over a five-year period. Employee participants may be awarded shares of restricted Common Stock, stock options and other Common Stock-based awards. Actual awards of restricted shares are based on attainment of various levels of certain Company performance criteria within a three- year period. Restrictions lapse upon actual award at the end of the three-year performance period. Shares not awarded are forfeited. Dividends earned on restricted stock issued through the EIP are invested in additional restricted stock under the EIP. Such stock acquired is subject to the same restrictions. The number of restricted shares issued in 1994 to employee participants was 167,300. Stock options granted in 1994 are nonqualified and are exercisable three years after but within 10 years from the date of grant. Stock options are priced at an amount at least equal to 100% of the fair market value of Common Stock on the date of grant. As of December 31, 1994, options on 167,300 shares of common stock were granted at a price of $21.125 per share. No options were eligible to be exercised in 1994.
In October 1994, the Board of Directors authorized reacquisition of up to three million shares of the Company's Common Stock. Management will use its discretion, based on market conditions, as to the timing and price of shares repurchased. There is no schedule or specific share price target associated with the acquisition and the authorized number of shares will not be affected. Shares repurchased are cancelled. During 1994,the Company reacquired 221,700 shares at prices ranging from $16.50 to $18.125 per share.
NOTE 10. COMMITMENTS AND CONTINGENCIES
Construction Program
ACE's cash construction expenditures for 1995, which excludes AFDC and customer contributions are estimated to be approximately $116 million. Current commitments for the construction of major production and transmission facilities approximate $23 million, of which it is estimated that $19 million will be expended in 1995.
Insurance Programs
ACE is a member of certain insurance programs that provide coverage for decontamination and property damage to members' nuclear generating plants. Facilities at the Peach Bottom, Salem and Hope Creek stations are insured against property damage losses up to $2.75 billion per site under these programs.
In addition, ACE is a member of an insurance program which provides coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specific conditions. The insurer for nuclear extra expense insurance provides stated value coverage for replacement power costs incurred in the event of an outage at a nuclear unit resulting from physical damage to the nuclear unit. The stated value coverage is subject to a deductible period of the first 21 weeks of any outage. Limitations of coverage include, but are not limited to, outages (1) not resulting from physical damage to the unit, (2) resulting from any government mandated shutdown of the unit, (3) resulting from any gradual deterioration, corrosion, wear and tear, etc. of the unit, (4) resulting from any intentional acts committed by an insured and (5) resulting from certain war risk conditions. Under the property and replacement power insurance programs, ACE could be assessed retrospective premiums in the event the insurers' losses exceed their reserves. As of December 31, 1994, the maximum amount of retrospective premiums ACE could be assessed for losses during the current policy year was $6.6 million under these programs.
The Price-Anderson provisions of the Atomic Energy Act of 1954, as amended by the Price-Anderson Amendments Act of 1988, govern liability and indemnification for nuclear incidents. All nuclear facilities could be assessed, after exhaustion of private insurance, up to $79.275 million each, payable at $10 million per year, per reactor and per incident. Based on its ownership share of nuclear facilities, ACE could be assessed up to $27.6 million per incident. This amount would be payable at $3.48 million per year, per incident.
Energy and Capacity Arrangements
UTILITY SOURCES
ACE has an arrangement for the purchase of 125 MWs of capacity and related energy from Pennsylvania Power and Light through September 30, 2000. Capacity costs, including certain deferred charges, totaled $26.6 million, $24.4 million and $25.1 million, and energy costs totaled $10.8 million, $11.2 million and $13.4 million in 1994, 1993 and 1992, respectively. Commitments for capacity costs expected to be incurred are $11.7 million, $12.0 million, $12.3 million, $12.6 million, $14.2 million and $12.3 million in each of the years 1995-2000, respectively.
ACE's arrangement for the purchase of 200 MWs of capacity and related energy from PECO expired May 31, 1994. Capacity costs charged to Purchased Capacity expense totaled $25.6 million through May 1994 and $55.9 million and $52.5 million for 1993 and 1992, respectively. Energy costs for the same periods amounted to $11.4 million, $21.0 million and $19.2 million, respectively. ACE also had another arrangement with PECO for the purchase of energy only which terminated in October 1994. Energy costs under this arrangement amounted to $32.5 million, $19.0 million and $17.5 million in 1994, 1993 and 1992, respectively.
ACE is a member of the Pennsylvania-New Jersey-Maryland Interconnection (PJM), an integrated power pool that is connected with other utilities for the interchange of energy on an as-needed and as-available basis. ACE is required to plan for reserve capacity based on aggregate PJM requirements allocated to member companies. ACE has satisfied its current reserve requirements. ACE also has an interchange agreement with the City of Vineland, New Jersey, which operates a municipal utility located in ACE's service territory. The cost of energy purchased through interchange agreements totaled $10.4 million, $9.9 million and $9.4 million in 1994, 1993 and 1992, respectively.
NONUTILITY SOURCES
ACE has contracted for a total of 569 MWs of capacity and related energy from four nonutility sources. The last two projects under contract for 388 MWs became operational in 1994. Non-utility capacity costs totaled $77.0 million, $30.2 million and $24.4 million, and energy costs totaled $62.5 million, $36.0 million and $27.6 million, in 1994, 1993 and 1992, respectively. Capacity and energy costs from nonutility sources are recovered through the LEC.
Environmental Matters
The provisions of Title IV of the Clean Air Act Amendments of 1990 (CAAA) will require, among other things, phased reductions of sulfur dioxide (SO2) emissions by 10 million tons per year, and a limit on S02 emissions nationwide by the year 2000, and reductions in emissions of nitrogen oxides (NOx) by approximately 2 million tons per year. ACE's wholly-owned B.L. England Units 1 and 2 and its jointly-owned Conemaugh Station Units 1 and 2 are affected during Phase I (1995) and all of ACE's other fossil-fuel steam generating units are affected by Phase II (2000) of the CAAA. ACE has installed a scrubber on B.L. England Unit 2 at a cost of $81 million which went into service in December 1994. By scrubbing B.L. England Unit 2, Phase I S02 emission requirements are met for both B.L. England Units 1 and 2. The Conemaugh owners installed a scrubber on Conemaugh Unit 1 which went into service in December 1994. ACE's 3.83% share of the cost was $11 million. A scrubber on Conemaugh Unit 2 is to be completed in 1995, with ACE's share of the cost estimated to be $4 million. The jointly-owned Keystone Station is impacted by the SO2 and NOx provisions of Title IV of the CAAA during Phase II. Currently, the Keystone owners plan to rely on utilizing emission allowances, and modified fuel content to a lesser extent, to meet compliance with the CAAA through the year 2000. In addition, certain purchase power arrangements will be affected by the CAAA, in amounts that are not presently determinable.
Federal and state legislation authorize various governmental authorities to issue orders compelling responsible parties to take cleanup action at sites determined to present danger from releases of hazardous substances. The various statutes impose joint and several liability without regard to fault for certain investigative and cleanup costs for all potentially responsible parties. ACE has received notification with respect to two sites within New Jersey as one of a number of alleged responsible parties for cleanup and remedial actions. ACE's maximum expense for these claims is not expected to exceed $1 million. ACE believes that insurance coverage is available to satisfy any amounts in excess of the self-insured limits associated with these particular claims should any liability result. The insurer for pollution liability insurance provides comprehensive excess general liability coverage, including pollution liability, for environmental costs incurred in the event of bodily injury or property damage resulting from the discharge or release of pollutants into or upon the land, atmosphere or water. Limitations of coverage include any pollution liability 1) resulting subsequent to the disposal of such pollutants, 2) resulting from the operation of a storage facility of such pollutants, 3) resulting in the formation of acid rain, 4) caused to property owned by an insured and 5) resulting from any intentional acts committed by an insured.
Other
ACE is subject to a performance standard for all of its jointly-owned nuclear units. This standard is used by the BPU in determining recovery of replacement energy costs resulting from poor nuclear performance. The standard establishes a target aggregate capacity factor within a zone of reasonable performance to be achieved by the units. Performance outside of the zone results in penalties or rewards. Any penalties incurred would not be permitted to be recovered from customers and would be charged against income. For 1994, the aggregate capacity factor of ACE's nuclear units is within the reasonable performance zone, which results in no penalty or reward.
A contract with an industrial company whereby ACE delivered process steam, water and by-product electricity was terminated by this company effective June 30, 1994. In 1993, ACE received approximately $12 million from this company for services and energy sales. In accordance with the termination agreement, ACE received $4.2 million in cash proceeds, 45,165 emission allowances valued at $6.5 million, and made provisions to retire certain equipment. A net gain of $2.4 million net of tax resulted. The steam and electricity needs of this company are provided by a nonutility cogeneration facility. ACE has a contract for the purchase of 188 MWs of capacity and energy from this facility.
In November 1994, ACE announced a program to reduce its workforce by up to 20% or 350 people. This program was initiated so that ACE can better position itself for the more competitive environment within the electric industry. Under the program, certain employees will separate from the company and be entitled to a severance package, including salary continuation, lump sum payments, extended medical benefits and outplacement services. In December 1994, ACE accrued the costs of the workforce reduction in the amount of $17.3 million, net of tax of $9.3 million, or $.32 in earnings per share. Included is ACE's share of an early retirement program of a jointly-owned nuclear station. ACE's employee separations are expected to be substantially completed by March 1, 1995.
AGI, through its subsidiaries, has partnership interests in common with affiliates of Columbia Gas System, Inc. (Columbia) in certain cogeneration projects. Columbia has been operating under Chapter 11 of the Federal Bankruptcy Code since 1991. A reorganization plan for Columbia and its principal pipeline unit is expected to be filed with the U.S. Bankruptcy Court in the first half of 1995. AGI does not anticipate any significant changes in its partnership arrangements as a result of Columbia's reorganization plan.
The Energy Policy Act of 1992 permits the Federal government to assess investor-owned electric utilities that have ownership interests in nuclear generating facilities an amount to fund the decontamination and decommissioning of three Federally operated nuclear enrichment facilities. Based on its ownership in five nuclear generating units, ACE recorded a liability of $6.6 million and $8 million at December 31, 1994 and 1993, respectively, for its obligation to be paid over the next 13 years. ACE has an associated regulatory asset of $7.2 million and $8.4 million at December 31, 1994 and 1993, respectively. Amounts are currently being recovered in rates for this liability and the regulatory asset is concurrently being amortized to expense based on the annual assessment billed by the Federal government.
NOTE 11. LEASES
ACE leases various types of property and equipment for use in its operations. Certain of these lease agreements are capital leases consisting of the following at December 31:
(000) 1994 1993 Production plant $13,521 $13,521 Less accumulated amortization 9,707 8,846 Net 3,814 4,675 Nuclear fuel 38,216 40,593 Leased property-net $42,030 $45,268
ACE has a contractual obligation to obtain nuclear fuel for the Salem, Hope Creek and Peach Bottom stations. The asset and related obligation for the leased fuel are reduced as the fuel is burned and are increased as additional fuel purchases are made. No commitments for future payments beyond satisfaction of the outstanding obligation exist. Operating expenses for 1994, 1993 and 1992 include leased nuclear fuel costs of $14.1 million, $13.9 million and $13.5 million, respectively, and rentals and lease payments for all other capital and operating leases of $5.3 million, $4.8 million and $4.8 million, respectively. Future minimum rental payments for all noncancellable lease agreements are not significant to ACE's operations. Rental charges of other subsidiary companies are not significant.
NOTE 12. QUARTERLY FINANCIAL RESULTS (UNAUDITED)
Quarterly financial data, reflecting all adjustments necessary in the opinion of the Company for a fair presentation of such amounts, are as follows:
Operating Operating Net Earnings Dividends Paid Quarter Revenues Income Income Per Share Per Share 1994 (000) (000) (000) 1st $232,098 $ 39,712 $22,862 $ .43 $ .385 2nd 205,822 30,427 16,798 .31 .385 3rd 272,708 58,431 46,323 .85 .385 4th 202,410 24,969 (9,871) (.18) .385
Annual $913,039 $153,540 $76,113 $1.41 $1.54
1st $203,656 $ 35,445 $19,995 $ .38 $ .38 2nd 192,538 27,381 11,093 .21 .38 3rd 268,883 68,580 52,329 .99 .385 4th 200,596 28,177 11,880 .22 .385
Annual $865,675 $159,584 $95,297 $1.80 $1.53
Individual quarters may not add to the total due to rounding, and the effect on earnings per share of changing average number of common shares outstanding.
The revenues of ACE are subject to seasonal fluctuations due to increased sales and higher residential rates during the summer months.
Net Income reflects special charges aggregating $20.4 million, after tax of $10.9 million, or $.37 per share, recorded in Other Income during the fourth quarter of 1994. One of the charges is an accrual of the costs of workforce reductions for severance and benefits packages in the amount of $17.3 million, net of tax of $9.3 million, or $.32 per share. Another charge is an amount for ACE's share of deferred costs for studies at a nuclear station in the amount of $1.4 million, net of tax of $735 thousand, or $.02 per share. Also included is the write-down of the carrying value of ASP's commercial site of $1.7 million, net of tax of $926 thousand, or $.03 per share.
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
Information for this item concerning Directors of the Company is set forth in the section entitled "Nominees for Election" on page 2 of the Company's Notice of Annual Meeting of Shareholders and definitive Proxy Statement, which is incorporated by reference. The information required by Item 10 of Form 10-K with respect to the executive officers of the Company and the directors of ACE is, pursuant to Instruction 3 to Item 401(b) of Regulation S-K, set forth in Part I of this Form 10-K under the heading "Executive Officers".
ITEM 11

ITEM 11 EXECUTIVE COMPENSATION
Information for this item with respect to the amounts paid to the five most highly compensated executive officers of the Company and ACE, is set forth in the section entitled " Table 1- Summary Compensation Table" on page 14 of the Company's Notice of Annual Meeting of Shareholders and definitive Proxy Statement, which is incorporated herein by reference. The cash compensation paid to twelve executive officers of ACE, as a group, in 1994 was $2,598,662.
ITEM 12

ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by this item as to compliance with Section 16(a) of the Exchange Act is contained in the section captioned "Stock Ownership of Directors and Officers" on page 5 of the Company's Notice of Annual Meeting of Shareholders and definitive Proxy Statement, which is incorporated herein by reference.
ITEM 13

ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information for this item is set forth in the section entitled "Compensation Committee Interlocks and Insider Participation" on page 13 of the Company's Notice of Annual Meeting of Shareholders and definitive Proxy Statement, which is incorporated herein by reference.
PART IV
ITEM 14

ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Exhibits: See Exhibit Index attached. Financial Statements and Supplementary Schedules: The following information for Atlantic Energy, Inc. is filed as part of this report.
Management's Discussion and Analysis of Financial Condition and Results of Operation Page 40 Consolidated Statement of Income for the three years ended December 31, 1994 Page 55 Consolidated Statement of Cash Flows for the three years ended December 31, 1994 Page 56 Consolidated Balance Sheet - December 31, 1994 and December 31, 1993 Page 57 Consolidated Statement of Changes in Common Shareholders' Equity (Note 9 to Financial Statements) Page 59
Notes to Consolidated Financial Statements Page 81 Supplementary information regarding selected quarterly financial data (Unaudited) (Note 12 to Financial Statements) Page 81 Independent Auditors' Report Page 54 Report of Management Page 52
The following financial information, financial statements and notes to financial statements for ACE are filed herewith as Exhibit 28(a) and are incorporated by reference herein:
Management's Discussion and Analysis of Financial Condition and Results of Operation; Consolidated Statement of Income for the three years ended December 31, 1994; Consolidated Statement of Cash Flows for the three years ended December 31, 1994; Consolidated Balance Sheet-December 31, 1994 and December 31, 1993; Consolidated Statement of Changes in Common Shareholder's Equity; Notes to Consolidated Financial Statements; Independent Auditors' Report.
All other financial schedules are included in the Financial Statements and Notes to Financial Statements of the Company and ACE.
Reports on Form 8-K:
None SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, who also signed in the capacity indicated.
ATLANTIC ENERGY, INC. ATLANTIC CITY ELECTRIC COMPANY
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons in the capacities and on the date indicated.
Date: March 21, 1995 By: /s/ J. L. Jacobs J. L. Jacobs
Title: President and Chief Executive Officer and Director of Atlantic Energy, Inc. and Chairman, President, Chief Executive Officer and Director of Atlantic City Electric Company
Date: March 21, 1995 By: /s/ L. M. Walters L. M. Walters
Title: Acting Chief Financial Officer of Atlantic Energy, Inc. and Vice President-Treasurer and Assistant Secretary of Atlantic City Electric Company
DIRECTORS OF ATLANTIC ENERGY, INC.: Jos. Michael Galvin, Jr.* Kathleen MacDonnell* Gerald A. Hale* Richard B. McGlynn* Matthew Holden, Jr.* Bernard J. Morgan* Cyrus H. Holley* Harold J. Raveche* E. Douglas Huggard*
A MAJORITY OF DIRECTORS OF ATLANTIC CITY ELECTRIC COMPANY: Michael J. Chesser* James E. Franklin II* Meredith I. Harlacher, Jr.* Henry K. Levari, Jr.*
Date: March 21, 1995 *By: /s/ L. M. Walters L. M. Walters Attorney-in-Fact
EXHIBIT INDEX
3a Restated Certificate of Incorporation of Atlantic Energy, Inc. (File No. 1-9760, Form 10-Q for quarter ended September 30, 1987-Exhibit 4(a)); Certificate of Amendment to restated Certificate of Incorporation of Atlantic Energy, Inc. dated April 15, 1992. File No. 33-53511, Form S-8 dated May 6, 1994-Exhibit No. 3(ii).
3b By-Laws of Atlantic Energy, Inc. as amended August 8, 1991 (File No. 1-9760, Form 10-K for year ended December 31, 1991- Exhibit No. 3b).
3c Agreement of Merger between Atlantic City Electric Company and South Jersey Power & Light Company filed June 30, 1949, and Amendments through May 3, 1991 (File No. 2-71312-Exhibit No. 3(a); File No. 1-3559, Form 10-Q for quarter ended June 30, 1982- Exhibit No. 3(b); Form 10-Q for quarter ended March 31, 1985- Exhibit No. 3(a); Form 10-Q for quarter ended March 31, 1987- Exhibit No. 3(a): Form 8-K dated October 12, 1988-Exhibit No. 3(a); Form 10-K for fiscal year ended December 31, 1990-Exhibit No. 3c; and Form 10-Q for quarter ended September 30, 1991- Exhibit No. 3c).
3d By-Laws of Atlantic City Electric Company, as amended April 24, 1989 (File No. 1-3559, Form 10-Q for the quarter ended September 31, 1989-Exhibit No. 3).
4a Purchase Agreement, dated as of July 17, 1974, with respect to 9.96% Cumulative Preferred Stock of Atlantic City Electric Company (File No. 2-52000-Exhibit No. 2(hh)).
4b Purchase Agreement, dated as of December 1, 1977, with respect to $8.25 No Par Preferred Stock of Atlantic City Electric Company (File No. 2-60966-Exhibit No. 2(d)).
4c Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York (formerly Irving Trust Company) and Supplemental Indentures through September 1, 1993 (File No. 2-66280-Exhibit No. 2(b); File No. 1- 3559, Form 10-K for year ended December 31, 1980-Exhibit No. 4(d); Form 10-Q for quarter ended June 30, 1981-Exhibit No. 4(a); Form 10-K for year ended December 31, 1983-Exhibit No. 4(d); Form 10-Q for quarter ended March 31, 1984-Exhibit No. 4(a); Form 10-Q for quarter ended June 30, 1984-Exhibit 4(a); Form 10-Q for quarter ended September 30, 1985-Exhibit 4; Form 10-Q for quarter ended March 31, 1986-Exhibit No. 4; Form 10-K for year ended December 31, 1987-Exhibit No. 4(d); Form 10-Q for quarter ended September 30, 1989-Exhibit No. 4(a); Form 10-K for year ended December 31, 1990-Exhibit No. 4(c); File No. 33-49279-Exhibit No. 4(b); File No. 1-3559, Form 10-Q for the quarter ended September 30, 1993 - Exhibits 4(a) & 4(b); Form 10-K for the year ended December 31, 1993 - Exhibit 4c(i); File no. 1-3559, Form 10-Q for the quarter ended June 30, 1994 - Exhibit 4(a); File No. 1-3559, Form 10-Q for the quarter ended September 30, 1994 - Exhibit 4(a).
4c(1) Indenture Supplemental dated as of November 1, 1994 to Mortgage and Deed of Trust dated January 15, 1937 between Atlantic City Electric Company and The Bank of New York filed herewith.
4e Agreement dated as of February 1, 1966, between Atlantic City Electric Company and Fidelity Union Trust Company and Supplement dated as of May 1, 1968. (File No. 1-3559, Form 8-K dated March 7, 1966-Exhibit 13(b)(2); Form 8-K dated June 6, 1968- Exhibit No. 13(b)(1)).
4f(1) Revolving Credit and Term Loan Agreement dated as of May 24, 1988 by and between ATE Investment, Inc. and The Bank of New York (File No.1-9760, Form 10-K for year ended December 31, 1988- Exhibit No. 4g(1)).
4f(2) Support Agreement dated as of May 24, 1988 between Atlantic Energy, Inc. and ATE Investment, Inc. (File No. 1-9760, Form 10-K for year ended December 31, 1988-Exhibit No. 4g(2)).
4f(3) Letter Agreement dated as of May 24, 1988 between Atlantic Energy, Inc. and The Bank of New York (File No. 1-9760, Form 10-K for year ended December 31, 1988-Exhibit No. 4g(3)).
4f(4) Amendment No. 1 dated as of February 22, 1989 to Revolving Credit and Term Loan Agreement dated as of May 24, 1988 by and between ATE Investment, Inc. and The Bank of New York (File No. 1-9760, Form 10-K for the fiscal year ended December 31, 1988).
4f(5) Amendment No. 2 dated as of June 1, 1991, to Revolving Credit and Term Loan Agreement dated as of May 24, 1988 by and between ATE Investment, Inc. and The Bank of New York (File No. 1-9760, Form 10-K for year ended December 31, 1991-Exhibit No. 4f(5)).
10a(1) Atlantic Energy, Inc. Directors Deferred Compensation Plan revised as of February 4, 1988 (File No. 1-9760, Form 10-K for year ended December 31, 1988-Exhibit No. 10a(1)).
10a(2) Description of amendment to the Deferred Compensation Plan for Directors effective December 10, 1992 (File No. 1-9760, Form 10-K for year ended December 31, 1992-Exhibit No. 10a(1)).
10a(3) Deferred Compensation Plan for Employees of Atlantic Energy, Inc. and Participating Subsidiaries (File No. 1-9760, Form 10-K for year ended December 31, 1988-Exhibit No. 10a(2)).
10a(4) Description of amendment to Deferred Compensation Plan for Employees of Atlantic Energy, Inc. and Participating Subsidiaries effective December 10, 1992 (File No. 1-9760, Form 10-K for year ended December 31, 1992-Exhibit No. 10a(2)).
10a(5) Supplemental Executive Retirement Plan for Officers of Atlantic City Electric Company, as amended effective March 1, 1990 (File No. 1-9760, Form 10-K for year ended December 31, 1989-Exhibit No. 10a(4)).
10a(6) Description of amendment to Supplemental Executive Retirement Plan effective December 10, 1992 (File No. 2-9760, Form 10-K for year ended December 31, 1992-Exhibit 10a(3)).
10a(7) Executive Medical Expense Reimbursement Plan for Officers of Atlantic City Electric Company (File No. 1-3559, Form 10-K for year ended December 31, 1985-Exhibit No. 10a(5)).
10a(8) Copy of Management Annual Incentive Plan of Atlantic Energy, Inc. and its subsidiaries, effective January 1, 1992 (File No. 1-9760, Form 10-K for year ended December 31, 1991- Exhibit No. 10a(5)).
10a(9) Copy of Atlantic Electric Excess Benefit Retirement Income Program, as amended, effective as of August 2, 1990 (File No. 1-3559, Form 10-K for year ended December 31, 1991-Exhibit No. 10a(6)).
10a(10) Description of amendment to the Excess Benefit Retirement Income Program effective December 10, 1992 (File No. 1-9760, Form 10-K for year ended December 31, 1992-Exhibit 10a(6)).
10a(11) Agreement, effective as of February 1, 1990, between Atlantic City Electric Company and E. Douglas Huggard (File No. 1-9760, Form 10-K for year ended December 31, 1989-Exhibit No. 10a(8)).
10a(12) Agreement entered February 11, 1993 between Atlantic City Electric Company and E. Douglas Huggard (File No. 1-9760, Form 10-K for year ended December 31, 1992-Exhibit No. 10a(7)).
10a(13) Copy of Atlantic City Electric Company Long-Term Performance Incentive Plan, as amended effective November 1, 1990 (File No. 1-3559, Form 10-K for year ended December 31, 1991- Exhibit No. 10a(8)).
10a(14) Atlantic Energy, Inc. Retirement Plan for Directors, as amended effective November 13, 1991 (File No. 1-9760, Form 10-K for year ended December 31, 1991-Exhibit No. 10a(9)).
10a(15) Copy of Atlantic Energy, Inc. Restricted Stock Plan for Non-employee Directors, effective January 1, 1991 (File No. 1- 9760, Form 10-K for year ended December 31, 1991-Exhibit No. 10a(10)).
10a(16) Agreement dated February 11, 1993 between Atlantic City Electric Company and Jerrold L. Jacobs (File No. 1-3559, Form 10- K for the year ended December 31, 1994 - Exhibit No. 10a(16)).
10a(17) Agreement dated February 10, 1994 between Atlantic City Electric Company and Meredith I. Harlacher, Jr. (File No. 1`- 3559, Form 10-K for the year ended December 31, 1993 - Exhibit No. 10a(17)).
10a(18) Agreement dated February 10, 1994 between Atlantic City Electric Company and Henry K. Levari, Jr. (File No. 1-3559, Form 10-K for the year ended December 31, 1993 - Exhibit No. 10a(18)).
10a(19) Agreement dated February 10, 1994 between Atlantic City Electric Company and J. G. Salomone, Amendment to Agreement Termination and Release Agreement dated January 31, 1995 between Atlantic City Electric Company and J. G. Salomone (File No. 1- 3559, Form 10-K for the year ended December 31, 1993 - Exhibit No. 10a(19)); Amendment to Agreement Termination and Release Agreement between Atlantic City Electric Company and J. G. Salomone, filed herewith.
10a(20) Agreement dated January 10, 1994 between Atlantic City Electric Company and Michael Chesser (File No. 1-3559, Form 10-K for the year ended December 31, 1993 - Exhibit No. 10a(20)).
10a(21) Employment Termination Agreement dated February 17, 1994 between John R. Lilly and Atlantic Energy, Inc. (File No. 1-3559, Form 10-K for the year ended December 31, 1993 - Exhibit No. 10a(21)).
10a(22) Retirement and Release Agreement dated as of October 28, 1992 between Thomas E. Freeman and Atlantic City Electric Company (File No. 1-3559, Form 10-K for the year ended December 31, 1993 - - Exhibit No. 10a(22)).
10a(23) Agreement dated October 1, 1994 between Atlantic City Electric Company and James E. Franklin II, filed herewith.
10a(24) Termination and Release Agreement dated March 31, 1994 between Atlantic City Electric Company and S. D. McMillian, filed herewith.
10a(25) Termination and Release Agreement dated June 22, 1994 between Atlantic City Electric Company and J. J. Lees, filed herewith.
10a(26) Atlantic Energy, Inc. Equity Incentive Plan (File No. 33-53511, Form S-8 filed May 6, 1994-Exhibit 10.)
10b(1) Agreement as to ownership as tenants in common of the Salem Nuclear Generating Station Units 1, 2, and 3, dated November 24, 1971, and of Supplements, dated as of September 1, 1975, and as of January 26, 1977 (File No. 2-43137-Exhibit No. 5(p); File No. 2-60966-Exhibit No. 5(m); and File No. 2-58430- Exhibit No. 5(o)).
10b(2) Agreement as to ownership as tenants in common of the Peach Bottom Atomic Power Station Units 2 and 3, dated November 24, 1971 and of Supplements dated as of September 1, 1975 and as of January 26, 1977 (File No. 2-43137-Exhibit No. 5(o); File No. 2-60966-Exhibit No. 5(j); File No. 2-58430-Exhibit No. 5(m)).
10b(3) Owners Agreement, dated April 28, 1977 between Atlantic City Electric Company and Public Service Electric & Gas Company for the Hope Creek Generating Station Units No. 1 and 2 (File No. 2-60966-Exhibit No. 5(v)).
10b(3-1) Amendment to Owners Agreement for Hope Creek Generating Station, dated as of December 23, 1981, between Atlantic City Electric Company and Public Service Electric & Gas Company (File No. 1-3559, Form 10-K for year ended December 31, 1983-Exhibit No. 10b(3-2)).
10b(4) Pennsylvania-New Jersey-Maryland Interconnection Agreement, dated September 26, 1956 between Public Service Electric & Gas Company, Philadelphia Electric Company, Pennsylvania Power & Light Company, Baltimore Gas & Electric Company, Jersey Central Power & Light Company, Metropolitan Edison Company, Pennsylvania Electric Company, Potomac Electric Power Company and supplemental agreements through June 15, 1977 (File No. 1-3559, Form 10-K for year ended December 31, 1981- Exhibit No. 10(p)).
10b(5) Pennsylvania-New Jersey-Maryland Interconnection Supplemental Agreement, dated March 26, 1981, between Public Service Electric & Gas Company, Philadelphia Electric Company, Pennsylvania Power & Light Company, Baltimore Gas & Electric Company, Jersey Central Power & Light Company, Metropolitan Edison Company, Pennsylvania Electric Company, Potomac Electric Power Company, Atlantic City Electric Company and Delmarva Power & Light Company (File No. 1-3559, Form 10-Q for quarter ended March 31, 1981-Exhibit No. 20b).
24 Independent Auditors' Consent, filed herewith.
25a Powers of Attorney for Atlantic Energy, Inc. dated as of March 9, 1995, filed herewith.
25b Powers of Attorney for Atlantic City Electric Company dated as of March 6, 1995, filed herewith.
27 Financial Data Schedules for Atlantic Energy, Inc. and Atlantic City Electric Company for periods ended December 31, 1994.
28(a) Consolidated Financial Statements, Notes to Financial Statements, Management's Discussion and Analysis of Results of Operation and Financial Condition, and Independent Auditors' Report for Atlantic City Electric Company for the three years ended December 31, 1994, filed herewith.
28(b) Supplemental Financial Schedules for Atlantic Energy, Inc. and Atlantic City Electric Company for the three years ended December 31, 1994, filed herewith.