FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
OR
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Registrant; State of I.R.S.Employer
Commission Incorporation; Address; Identification
File No and Telephone Number Number
1-9760 ATLANTIC ENERGY, INC. 22-2871471
(a New Jersey Corporation)
6801 BLACK HORSE PIKE,
PLEASANTVILLE, NEW JERSEY 08232
609-645-4500
1-3559 ATLANTIC CITY ELECTRIC COMPANY 21-0398280
(a New Jersey Corporation)
6801 BLACK HORSE PIKE, P.O Box 1264
PLEASANTVILLE, NEW JERSEY 08232
609-645-4100
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
Common Stock, No Par Value New York Stock Exchange
of Atlantic Energy, Inc. Philadelphia Stock Exchange
Pacific Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Rule 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrant's knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10K. X
Estimated aggregate market value of the voting stock of
Atlantic Energy, Inc. held by non-affiliates at March 6, 1995,
was $976,552,108.88 based on a closing price of $18.375 per share
for the 53,145,693 outstanding shares at such date. Atlantic
Energy, Inc. owns all of the 18,320,937 outstanding shares of
Common Stock of Atlantic City Electric Company.
Documents Incorporated by Reference:
Certain sections of the Notice of Annual Meeting of
Shareholders and Proxy Statement in connection with the
Annual Meeting of Shareholders, to be held April 26, 1995, have
been incorporated by reference to provide information required by
the following parts of this report:
Part III-Item 10, Directors and Executive Officers of the
Registrant; Item 11, Executive Compensation; Item 12, Security
Ownership of Certain Beneficial Owners and Management; Item 13,
Certain Relationships and Related Transactions.
This combined Form 10-K is filed separately by Atlantic Energy,
Inc. and Atlantic City Electric Company. Information contained
herein relating to any individual registrant is filed by such
registrant on its own behalf. Atlantic City Electric Company
makes no representation as to information relating to Atlantic
Energy, Inc.
PART I
ITEM 1 BUSINESS 1
General 1
Atlantic City Electric Company 1
Competition 2
Nonutility Subsidiaries 4
Construction and Financing 6
Rates 8
Energy Requirements and Power Supply 9
Power Pool and Interconnection Agreements 10
Power Purchases and Sales 10
Capacity Planning 11
Nonutility Generation 13
Nuclear Generating Station Developments 13
Hope Creek Station 15
Salem Station 16
Peach Bottom 18
Fuel Supply 20
Oil 20
Coal 21
Gas 21
Nuclear Fuel 21
Regulation 25
Environmental Matters 27
General 27
Air 30
Water 32
Executive Officers 35
ITEM 2 PROPERTIES 37
ITEM 3 LEGAL PROCEEDINGS 37
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS 37
PART II 37
ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS 37
ITEM 6 SELECTED FINANCIAL DATA 39
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS 40
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 52
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE 82
PART III
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE
REGISTRANT 82
ITEM 11 EXECUTIVE COMPENSATION 82
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT 82
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 82
PART IV 82
ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K 82
SIGNATURES 84
PART I
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 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 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 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
PART II
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:
1994
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
1993
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 SELECTED FINANCIAL DATA
Selected financial data for the Company and ACE for each of
the last five years is listed below.
Atlantic Energy, Inc.
1994 1993 1992 1991 1990
(Thousands of Dollars)
Operating
Revenues $ 913,039 $ 865,675 $ 816,825 $ 808,374 $ 740,894
Net Income $ 76,113 $ 95,297 $ 86,210 $ 85,635 $ 68,879
Earnings per Average
Common Share $ 1.41 $ 1.80 $ 1.67 $ 1.75 $ 1.51
Total Assets
(Year-end) $2,545,555 $2,487,508 $2,219,338 $2,151,416 $2,006,010
Long Term Debt and
Redeemable Preferred
Stock (Year-end)(b) $ 940,788 $ 952,101 $ 842,236 $ 807,347 $ 747,877
Capital Lease
Obligations
(Year-end)(b) $ 42,030 $ 45,268 $ 49,303 $ 53,093 $ 57,971
Common Dividends
Declared $ 1.54 $ 1.535 $ 1.515 $ 1.495 $ 1.47
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 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 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
1993
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 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
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 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 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 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 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.