- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
----------------
1-9760 ATLANTIC ENERGY, INC. 22-2871471
(A NEW JERSEY CORPORATION)
6801 BLACK HORSE PIKE,
EGG HARBOR TOWNSHIP, NEW JERSEY 08234
609-645-4500
1-3559 ATLANTIC CITY ELECTRIC COMPANY 21-0398280
(A NEW JERSEY CORPORATION)
6801 BLACK HORSE PIKE
EGG HARBOR TOWNSHIP, NEW JERSEY 08234
609-645-4100
(COMMISSION (REGISTRANT; STATE OF INCORPORATION; (I.R.S. EMPLOYER
FILE NO.) ADDRESS; AND TELEPHONE NUMBER) IDENTIFICATION NUMBER)
----------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
8.25% Cumulative Quarterly Income Preferred
Securities, liquidation preference $25 per
preferred security issued by Atlantic Capital
I New York 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 Item
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
As of March 1, 1998, Atlantic Energy, Inc. had no estimated aggregate market
value of voting stock held by non-affiliates. Conectiv, Inc. owns all of the
18,320,937 outstanding shares of Common Stock of Atlantic City Electric
Company.
This combined Form 10-K is filed separately by Conectiv, Inc. as successor
to 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
Merger.................................................................. 1
Competition............................................................. 2
New Jersey Energy Master Plan........................................... 3
Nonutility Subsidiaries................................................. 4
Construction and Financing.............................................. 6
Rates................................................................... 7
Demand Side Management.................................................. 8
Energy Requirements and Power Supply.................................... 8
Power Pool and Interconnection Agreements............................... 9
Power Purchases and Sales............................................... 10
Bulk Power Marketing.................................................... 10
Capacity Planning....................................................... 10
Nonutility Generation................................................... 11
Nuclear Generating Station Developments................................. 11
Salem Station........................................................... 13
Hope Creek Station...................................................... 15
Peach Bottom Station.................................................... 15
Fuel Supply............................................................. 16
Oil................................................................... 16
Coal.................................................................. 16
Gas................................................................... 17
Nuclear Fuel............................................................ 17
Nuclear Fuel Disposal................................................... 17
Nuclear Decommissioning................................................. 18
Regulation.............................................................. 19
Environmental Matters................................................... 20
General............................................................... 20
Air................................................................... 22
Water................................................................. 23
ITEM 2 PROPERTIES........................................................ 24
ITEM 3 LEGAL PROCEEDINGS................................................. 24
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............... 24
PART II
ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.......................................................... 25
ITEM 6 SELECTED FINANCIAL DATA........................................... 26
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS............................................ 27
ITEM 8 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA....................... 40
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE............................................. 86
PART III
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................ 86
ITEM 11 EXECUTIVE COMPENSATION............................................ 89
i
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT..... 95
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..................... 95
PART IV
ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.... 96
SIGNATURES................................................................. 97
ii
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or acronyms that
are found in this report:
TERM DEFINITION
---- ----------
ACE..................... Atlantic City Electric Company
ACO..................... Administrative Consent Order
AEE..................... Atlantic Energy Enterprises, Inc.
AEI..................... Atlantic Energy, Inc. or the Company
AEII.................... Atlantic Energy International, Inc.
AET..................... Atlantic Energy Technology, Inc.
AFDC.................... Allowance for Funds Used During Construction
AGI..................... Atlantic Generation Inc.
ASP..................... Atlantic Southern Properties
ATS..................... Atlantic Thermal Systems, Inc.
BPU..................... New Jersey Board of Public Utilities
BWR..................... Boiling water reactor
CAAA.................... Clear Air Act Amendments
CAFRA................... New Jersey Coastal Area Facility Review Act
CCE..................... Coalition for Competitive Energy
CCI..................... CoastalComm Inc.
CERCLA.................. Federal Comprehensive Environmental Response,
Compensation and Liability Act of 1980
CFC..................... Coalition for Fair Competition
CON..................... Certificate of Need
CORP.................... New Jersey Commission on Radiation Protection
CQIPS................... 8.25% Cumulative Quarterly Income Preferred
Securities
DCP..................... Deferred Compensation Plan for Employees
Delmarva................ Delmarva Power and Light Company
DOE..................... U. S. Department of Energy
DP&L.................... Delmarva Power and Light Company
DRBC.................... Delaware River Basin Commission
DRP..................... Dividend Reinvestment and Stock Purchase Plan
DRSP.................... Director Restricted Plan
DSM..................... Demand Side Management
EFNAA................... Electric Facilities Need Assessment Act
EIP..................... Equity Incentive Plan
EITF.................... Emerging Issue Task Force
EMF..................... Electric and magnetic fields
EMI..................... EMI International
EnerTech................ EnterTech Capital Partners, L.P.
Enerval................. Enerval, LLC
EPA..................... Environmental Protection Agency
EPAct................... Energy Policy Act of 1992
ESPP.................... Employee Stock Purchase Plan
FASB.................... Financial Accounting Standards Board
FERC.................... Federal Energy Regulatory Commission
GAAP.................... Generally Accepted Accounting Principles
GE...................... General Electric Company
GR&FT................... Gross Receipts and Franchise Tax
Hope Creek.............. Hope Creek Nuclear Generating Plant
HSW..................... Harrisburg Steam Works, Ltd.
iii
TERM DEFINITION
---- ----------
IGM..................... Interstate Gas Marketing
IPP..................... Independent power producer
ISO..................... Independent System Operator
IT...................... Information Technology Department
KW...................... Kilowatt-hours
LEC..................... Levelized Energy Clause
LLRW.................... Low-level radioactive waste
LLRWPA.................. Low Level Radioactive Policy Act
MTC..................... Market Transition Charge
MTN..................... Medium Term Notes
MW...................... Megawatt
MWhrs................... Megawatt hours
NJEDA................... New Jersey Economic Development Authority
NJDEP................... New Jersey Department of Environmental Protection
NJPDES.................. New Jersey Pollution Discharge Elimination System
NOx..................... Nitrogen Oxide
NPDES................... National pollution discharge elimination system
NRC..................... Nuclear Regulatory Commission
NUG..................... Nonutility generators
NWPA.................... Nuclear Waste Policy Act
OAL..................... Office of Administration Law
OPEB.................... Other Post-Retirement Benefits
OTRA.................... Off-Tariff rate agreements
PCCA.................... Paxton Creek Cogeneration Associates
Peach Bottom............ Peach Bottom Atomic Power Station
PE...................... PECO Energy Company
PJM..................... Pennsylvania-Jersey-Maryland Interconnection Assoc.
Plan.................... New Jersey Energy Master Plan, Draft Phase II
PP&L.................... Pennsylvania Power & Light Company
PS...................... Public Service Electric and Gas Company
PUHCA................... Public Utility Holding Company Act of 1935
PURPA................... Public Utility Regulatory Policy Act
PWR..................... Pressurized water reactor
QF...................... Qualifying Facility
RATI.................... Readiness Assessment Team Inspection
RCRA.................... Federal Resource Conservation and Recovery Act of
1976
RHR..................... Residual Heat Removal System
RISC.................... Rate Intervention Steering Committee
Salem................... Salem Nuclear Generating Station
SALP.................... Systematic Assessment of Licensee Performance
SARA.................... Superfund Amendments and Reauthorization Act of
1986
SEC..................... Securities and Exchange Commission
SERP.................... Supplemental Executive Retirement Plan
SERT.................... Significant event response team
SIP..................... State implementation plans
SNJEI................... Southern New Jersey Economic Initiative
SO/2/................... Sulfur Dioxide
SOP96-1................. Statement of Position of the Accounting Standards
Board 96-1
"Environmental Remediation Liabilities"
Spill Act............... New Jersey Spill Compensation and Control Act
TEFA.................... Transitional Energy Facility Assessment
Y2K..................... Year 2000 problem
iv
PART I
ITEM 1 BUSINESS
GENERAL
Atlantic Energy, Inc. (AEI or the Company), the principal office of which is
located at 6801 Black Horse Pike, Egg Harbor Township, New Jersey, 08232-4130,
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 (PUHCA), and has claimed an exemption from
substantially all of the provisions of the 1935 Act. For a complete
description of the Company and its subsidiaries, see Note 1 of the Notes to
Consolidated Financial Statements herein.
Principal cash inflows of the Company include the receipt of dividends from
Atlantic City Electric Company (ACE) and loans outstanding from a revolving
credit and term loan facility established by AEI in September 1995. As of
December 31, 1997, AEI has $53.5 million outstanding under such facility.
Principal cash outflows of the Company in 1997 were primarily for the payment
of dividends to common shareholders.
ACE 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 wholly owned subsidiary, Deepwater
Operating Company, was merged into ACE on January 1, 1998 with no financial
impact upon ACE. ACE's principal office is located at 6801 Black Horse Pike,
Egg Harbor Township, New Jersey, 08232-4130, 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, 1997, ACE had over 480,000
customers and employed 1,423 persons, of which 624 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 normally occurs
during the summer months. Approximately 30% of 1997 revenues were recorded
during the quarter ended September 30, 1997.
MERGER
On August 12, 1996, the Boards of Directors of AEI and Delmarva Power &
Light Company (Delmarva) jointly announced an agreement to merge the companies
into a new company named Conectiv. Following the merger, AEI will be merged
into Conectiv, which will become the parent of Delmarva and ACE as well as
AEI's non-regulated subsidiaries. The purpose of the merger is to create a
regional company that share a common vision of the strategic path necessary to
succeed in the increasingly competitive utility and energy services
marketplace.
Following the approval of the merger by the shareholders of both companies
on January 30, 1997, AEI and Delmarva filed applications with the FERC, BPU,
the Delaware Public Service Commission, the Maryland Public Service
Commission, the Pennsylvania Public Utilities Commission and the Virginia
State Corporation Commission. On December 30, 1997, the BPU approved the
merger between AEI and Delmarva. Under the terms of the approval,
approximately 75 percent of the total average projected $21.12 million annual
merger savings for New Jersey ratepayers, or $15.75 million, will be returned
to customers, for an overall merger-related rate reduction of 1.7 percent.
In addition to the approval given by the BPU, the merger has also been
approved by the Delaware Public Service Commission, the Maryland Public
Service Commission, the Virginia State Corporation Commission, the
Pennsylvania Public Utilities Commission, the Nuclear Regulatory Commission
(NRC), the FERC and the Securities and Exchange Commission (SEC). Approval of
the merger in each of the state commissions has resulted in the following
retail base rate decreases:
1
ANNUALIZED
REVENUE
RETAIL ELECTRIC DECREASE EFFECTIVE DATE
--------------- ---------- --------------
Delaware................... $7.5 mil (1.5%) as of Merger
Delaware................... $0.6 mil (0.1%) one year after merger
Delaware................... $0.4 mil (0.1%) two years after merger
Maryland................... $3.5 mil (1.3%) as of merger date
Virginia................... $0.4 mil (1.5%) as of merger date
New Jersey................. $10.75 mil (1.2%) as of merger date net of PBOP
increase of $5.0 million
RETAIL GAS
----------
Delaware gas............... $0.5 mil (0.5%) two years after merger
In addition, Delmarva will contribute $340,000 per year to certain economic
development and societal programs in Maryland for three years after the
merger.
On February 26, 1998 the SEC issued an order approving the merger of
Delmarva and AEI. The Merger became effective on March 1, 1998.
COMPETITION
Competition exists and is expected to increase for certain electric energy
markets historically served exclusively by regulated utilities. In recent
years, changing laws and governmental regulations permitting competition from
other utilities as well as nonregulated energy suppliers have prompted some
customers to use self-generation or alternative sources to meet their electric
needs. The transition from strictly regulated to competitive resale and retail
markets is changing the structure of the utility industry and the way in which
it conducts business.
The PUHCA imposes substantial limitations on the business activities of
registered holding companies and their subsidiaries which are not imposed on
other utilities or electricity suppliers. Federal legislation has been
introduced in Congress to repeal PUHCA on both a stand-alone basis and as part
of a more sweeping move to deregulate the industry. At this time ACE cannot
predict the ultimate outcome of this matter. PUHCA reform could eliminate SEC
regulation of a holding company's financing activities and limitation on
business activities which do not apply to other holding companies.
The Public Utility Regulatory Policy Act (PURPA) created a new class of
generating facilities, operated by independent power producers (IPPs), and
required electric utilities to purchase the excess power from each IPP. As a
direct result of PURPA, ACE has long-term contracts with four such IPPs for
the purchase of 579 megawatts (MWs) of capacity and energy and experienced a
decline in its sales to industrial customers, three of which contracted with
IPPs for their power supply. ACE has subsequently regained two such customers.
By November 1997, electric utility restructuring bills in both the House and
Senate were introduced that included provisions for the repeal of PURPA. In
its present form PURPA is inconsistent with ongoing efforts to foster retail
competition. PURPA was premised on utilities continuing to be the exclusive
suppliers of electricity to all consumers within their territories. Federal
action with regard to PURPA is not likely to affect ACE's four existing IPP
contracts.
The Energy Policy Act of 1992 (EPAct) represented another significant step
toward deregulation of the electric utility industry. The EPAct facilitated
development of the wholesale power market and increased competition between
utility and non-utility generators (NUGs). The EPAct created a class of NUGs
called exempt wholesale generators and gave the FERC the authority to order
open access to the transmission facilities of electric utilities and the
wheeling of wholesale electric power.
2
In April 1996, the FERC issued Order No. 888 "Promoting Wholesale
Competition Through Open Access Non-Discriminatory Transmission Service by
Public Utilities; Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities". The Order was designed to remove impediments to
competition in the wholesale bulk power marketplace, to bring more efficient,
lower cost power to electricity consumers, and provide an equitable means to
transition the industry to the new environment. Under this Order, utilities
that own, control or operate interstate transmission facilities are required
to offer transmission services for wholesale energy transactions to others on
a nondiscriminatory basis. Tariffs were established by the utilities for these
services, under which a utility must also apply these tariffs to its own
wholesale energy transactions. The Order also permits utilities to seek
recovery of legitimate, prudent and verifiable unrecovered costs that become
stranded as a result of providing open access transmission services pursuant
to the Order. A utility may have been obligated to incur a cost on behalf of a
customer(s) in the reasonable expectation of providing service and recovery of
that cost. When the customer(s) no longer uses the utility for the service
related to the cost, or there is a change in a regulator's recovery policy due
to market forces concerning the cost, the cost may become stranded if the
utility is precluded from recovery.
As the electric utility industry transitions from a regulated to a
competitive industry, utilities may not be able to recover certain costs which
are known as "stranded" costs. Potential types of stranded costs could be (i)
above-market costs associated with generation facilities or long-term power
purchase agreements and (ii) regulatory assets, which are expenses deferred
and expected to be recovered from customers in the future. (See Note 12 in
AEI's consolidated financial statements for further information on ACE's
potential stranded costs.)
Flex-rate legislation promulgated into law in New Jersey in July 1995 allows
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. In
addition, on a case-by-case basis, the law allows utilities to petition the
BPU for the right to offer customers, who meet certain conditions, off-tariff,
discounted rates. The law provides for the recovery of up to 50 percent of the
value of discounts in a subsequent base rate case if it can be adequately
demonstrated that the discount benefits all ratepayers. Off-tariff pricing
arrangements with several of ACE's customers have been arranged. Refer to
"Results of Operations" in AEI's Management's Discussion and Analysis of
Financial Condition and Results of Operations herein for further information
regarding off-tariff rates (OTRAs).
NEW JERSEY ENERGY MASTER PLAN
In April 1997, the BPU issued its final report containing findings and
recommendations on the electric utility industry restructuring in New Jersey
to the Governor and the State Legislature for their consideration. The
recommendation for a phase-in of retail choice to electric consumers calls for
choice to 10% of all customers beginning October 1, 1998 and to 100% by July
1, 2000. The report required each electric utility in New Jersey to file
complete restructuring plans, stranded cost filings and unbundled rate filings
by July 15, 1997. The report would allow utilities the opportunity to recover
stranded costs on a case-by-case basis, with no guarantee of 100 percent
recovery of eligible stranded costs.
Transmission service would be provided by an Independent System Operator
(ISO), which would be responsible for maintaining the reliability of the
regional power grid. The ISO would be regulated by the FERC. The utility would
continue to pass through the cost of transmission to customers in its
regulated rates. The report also calls for further review of metering and
billing in order to make recommendations related to introduction of
competition into the customer services area.
The report suggests that the BPU is committed to assuring that a fully
competitive marketplace exists prior to the ending of its economic regulation
of power supply. At a minimum, utility generating assets and functions must be
functionally separated and operate at arms-length from the transmission,
distribution and customer service functions of the electric utility. The BPU
reserves final judgment on the issue of requiring divestiture of utility
generating assets until detailed analyses of the potential for market power
abuses by utilities have been performed. In addition, the BPU believes that it
is necessary to have a fully independent and operating ISO prior to the
implementation of customer choice.
3
ACE filed its response to the BPU on July 15, 1997. ACE's restructuring plan
met the BPU's recommendations for phase-in of retail electric access based on
a first-come, first-served basis, proposing choice to 10% of all customers
beginning October 1, 1998 and to 100% by July 1, 2000. Customers remaining
with ACE will be charged a market-based electricity price beginning October 1,
1998. The restructuring plan included a two-phased approach to future rate
reductions.
In an October 31, 1997 letter to the BPU, ACE added specificity to the
framework set out in the restructuring plan with regard to steps ACE
anticipated taking to meet the BPU's rate reduction and restructuring goals.
First, specific, definable cost reductions of approximately 4% after 1998 were
outlined. Further, ACE offered that an appropriate resolution of the merger
proceedings will allow ACE to reduce its rates, due to the merger,
approximately 1.25% upon consummation of the change in control. In addition,
ACE's current estimate showed that, through the use of securitized debt for
the full amount of stranded costs associated with its own generation assets, a
further rate decrease of up to 2% was possible based on appropriate
legislation and orders of the BPU with respect to securitization. Finally, ACE
estimates that the results of good-faith negotiations with the nonutility
generators (NUGs) could provide a reduction of up to an additional 1.75%. In
summary, ACE outlined a total rate reduction of 9% by the end of the
transition.
On January 28, 1998, the BPU issued its order establishing the procedural
schedule regarding the restructuring plan. Under that order, hearings in the
restructuring plan are to be completed by mid-May 1998. It is anticipated that
the BPU will issue its final order during the summer of 1998.
ACE's filing supports full recovery of stranded costs, which ACE believes is
necessary to move to a competitive environment. On February 5, 1998 the
Company filed rebuttal testimony that updated its stranded cost estimate for
the effects of tax law changes in the State of New Jersey and modified certain
assumptions made in its estimates. The total stranded cost estimate in the
filing is approximately $1.2 billion with $812 million attributable to the NUG
contracts and $397 million related to wholly- and jointly-owned generation
investments. Arguments on the issue of stranded costs have been heard by the
Office of Administrative Law (OAL) during February 1998. The OAL is expected
to render a decision in May 1998.
If ACE's estimated amount of stranded costs are not fully recovered, ACE may
be required to recognize certain amounts as unrecoverable. As such, ACE may be
required to write-down asset values and such write-downs could be material.
The effect of competition on the Company's equity from reductions in profit
margins or extraordinary charges against income would reduce the amount of
common equity in the capital structure and could result in lowered credit
ratings on existing debt securities and higher corresponding financing costs.
To the extent that additional equity capital is required, issuances of common
stock may be necessary. To the extent that additional equity capital is
required, the effect would be dilutive on reported earnings per share, the
amount of which ACE cannot presently determine.
Other proposed regulatory and accounting changes have been suggested
relating to matters at the state and Federal level which could have operating
and financial implications for ACE. (See "Regulation" and "Environmental
Controls" herein for additional information and Note 12 of the accompanying
Notes to Financial Statements herein.)
NONUTILITY SUBSIDIARIES
Atlantic Energy Enterprises, Inc.
In January 1995, the Company formed a subsidiary, Atlantic Energy
Enterprises, Inc. (AEE), a holding company, to which ownership of the existing
nonutility businesses was transferred. Information regarding the principal
assets and the results of operation of each of these subsidiaries can be found
in Note 7 of AEI's Consolidated Financial Statements.
It is anticipated that following the Company's merger with Conectiv, Inc.,
several of the Company's non-regulated entities will be consolidated into
related Delmarva non-regulated entities. As such, the amount of
4
capital invested in these subsidiaries will be affected, to a large degree
upon the strategic business plans of Conectiv, 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.
Atlantic Thermal Systems, Inc. (ATS)
AEE's wholly-owned subsidiary, ATS, commenced operations in 1994 and is
engaged in the development, operation and maintenance of thermal heating and
cooling systems for large use commercial and industrial customers. ATS'
strategy is to develop energy centers using one central facility to host
multiple commercial and industrial customers in a concentrated geographic
area. Through a special purpose limited partnership, ATS currently provides
heating and cooling service to several commercial customers located in
Atlantic City under long-term requirements contracts. Construction is
substantially complete on the Midtown Energy Center, an $85 million district
heating and cooling production plant and distribution piping system, serving a
number of casino/hotel and other large use customers located in the Midtown
region of Atlantic City.
In April 1995, ATS filed a petition with the BPU for an Order declaring that
ATS is not a public utility subject to the BPU's jurisdiction by reason of its
business activities in Atlantic City. It is ATS' position that its service to
a limited number of large use energy consumers does not invoke the requisite
public interest that is a prerequisite to public utility classification. The
petition is still pending final resolution.
ATS is actively pursuing potential business opportunities throughout the
United States. Depending on the degree of success that ATS will have in
bringing these projects to completion, ATS anticipates the potential of an
additional capital investment of $200 million over the next five years.
Atlantic Generation, Inc. (AGI)
At December 31, 1997, AGI's activities were represented by partnership
interests in two cogeneration power projects:
PROJECT FUEL CAPACITY COMMERCIAL OWNERSHIP
LOCATION TYPE MEGAWATT (MW) OPERATION INTEREST
-------- ---- ------------- ---------- ---------
Pedricktown, New Jersey........... gas 116 1992 50%
Vineland, New Jersey.............. gas 46.5 1994 50%
Binghamton, New York.............. gas (decommissioned) 1992 33%
Subsidiaries of Tristar Ventures Corporation, a subsidiary of The Columbia
Gas System, Inc. have partnership interests in the Pedricktown and Vineland
projects. In addition to Tristar Ventures Corporation, Stone & Webster
Development Corporation has a one-third partnership interest in the Binghamton
project. In December 1996, the Boards of AEE and AEI authorized the
restructuring of Binghamton which became effective in January 1997. Under the
restructuring, the power purchase agreement with New York State Gas & Electric
was sold to a third party and the project debt was retired. The facility was
then decommissioned. As a result of the restructuring, AGI recorded a loss in
1996 from the sale of the Binghamton facility of $1.6 million, net-of-tax.
The Pedricktown facility is hosted by a chemical manufacturer, currently a
retail customer of ACE, and provides 116 MW of generating capacity to ACE. The
Vineland facility is hosted by a food processor and provides 46.5 MW of
capacity and related energy to the City of Vineland under a 25 year contract.
ATE Investment, Inc. (ATE)
ATE provides financing to affiliates and manages a portfolio of $80.4
million in investments in leveraged leases of three commercial aircraft and
two containerships. In August 1996, ATE joined with Safeguard
5
Scientifics, Inc., an unaffiliated company, to create EnerTech Capital
Partners, L.P., (EnerTech) an equity limited partnership to make, manage, own
and supervise private equity investments in early-to-late stage energy-related
growth companies. At December 31, 1997, EnerTech had invested $11.6 million in
eight such companies. ATE anticipates additional capital investment of $31.6
million over the next five years.
Enerval, LLC
In 1995, AEE and EMI International (EMI), formerly known as Cenerprise, a
subsidiary of Northern States Power, established Enerval, LLC (Enerval),
formerly known as Atlantic CNRG Services, LLC. AEE and EMI each own 50 percent
of Enerval. Enerval provides energy management services, including natural gas
procurement, transportation and marketing. Enerval has certain gas
transportation agreements, which include obligations for the transportation of
specified volumes of gas, or to make payments in lieu thereof. At December 31,
1997, Enerval was committed to approximately $3.4 million in such obligations
under generally short-term contracts.
CoastalComm, Inc.
CoastalComm, Inc. (CCI) operations consist of service agreement contracts
whereby CCI provides real estate and siting services to help facilitate
wireless network development and the development of local loop fiber optic
networks.
Atlantic Southern Properties, Inc.
The primary business of Atlantic Southern Properties, Inc. (ASP) is owning,
developing and managing commercial real estate property. ASP owns a 275,000
square foot office and warehouse facility in Mays Landing, New Jersey which is
occupied by AEE, ACE and third parties. In October 1997, ASP acquired a 34,000
square foot office building in Atlantic City, New Jersey which is planned to
be used for office space by the Company.
For further information regarding AEI's nonutility subsidiaries, refer to
Note 7 of the Notes to Financial Statements and to the Liquidity and Capital
Resources section of Management's Discussion and Analysis of Financial
Condition and Results of Operation herein.
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, undergoes continuous review. ACE's
construction expenditures will depend upon factors such as long-term load,
customer growth, the effects of competition and retail wheeling, 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's return on such
investments. 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. 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. The table below
presents ACE's estimated cash construction costs for utility plant for the
years 1998 through 2000:
1998 1999 2000 TOTAL
---- ---- ---- -----
(000)
Nuclear Generating............................ $ 5,163 $ 4,802 $ 2,489 $ 12,454
Fossil Steam Generating....................... 7,615 8,678 8,738 25,031
Transmission and Distribution................. 40,123 48,985 53,538 142,646
General Plant................................. 14,071 10,365 3,481 27,917
Combustion Turbine............................ 604 6,384 5,500 12,488
------- ------- ------- --------
Total Cash Construction Costs................. $67,576 $79,214 $73,746 $220,536
======= ======= ======= ========
6
For additional information regarding construction of a district heating and
cooling facility in Atlantic City, New Jersey refer to "Nonutility
Subsidiaries" herein.
ACE's debt securities are currently rated "A-/A3" by two major rating
agencies. Its preferred stock is rated "BBB+/baa1" and its commercial paper is
rated "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 retail electric service are subject to the approval of the
BPU. For information concerning changes in base rates and the levelized energy
clause (LEC) for the years 1995 through 1997 and certain other proceedings
relating to rates, see "Purchased Power" herein and Note 3 of the Notes to
Consolidated Financial Statements.
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 the standard, the composite target
capacity factor for such units is 70%, 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.
Adjustments to rates based on the nuclear unit performance standard is done
through ACE's annually adjusted LEC.
The 1997 composite capacity factor for Peach Bottom and Hope Creek was
84.1%. Salem Unit 2 returned to service on August 30, 1997 and ended 1997 with
a cycle capacity factor of approximately 80%. Salem Unit 1 has been out of
service since May 16, 1995 and is currently expected to return to service in
the second quarter of 1998. Based on an agreement among ACE, Division of
Ratepayer Advocate and the Staff of the BPU, the 1997 performance of the Salem
units was not to be included in the calculation of the composite capacity
factor for the purpose of assessing a penalty. In addition, no penalty would
be imposed on ACE for the years 1995 and 1996 as part of such agreement.
On February 27, 1997, the Coalition for Competitive Energy (CCE) and the
Coalition for Fair Competition (CFC) filed an appeal in the Superior Court of
New Jersey, Appellate Division based on the BPU's Summary Decision and Order
dated December 31, 1996 approving settlements regarding the rate treatment of
the Salem Nuclear Generating Station. The appeal alleges, among other things,
that the BPU's use of a Summary Order was illegal under the Administrative
Procedure Act. On March 12, 1997, ACE filed with the Superior Court of New
Jersey, Appellate Division, information statements in response to the appeal
filed by the CCE and CFC. On August 1, 1997, both the CCE and CFC withdrew
their respective appeals regarding this matter from the Superior Court,
Appellate Division. Subsequently, on August 5, 1997, an Order dismissing the
appeal was provided by the Superior Court of New Jersey, Appellate Division.
On April 11, 1997, the Rate Intervention Steering Committee (RISC) submitted
its brief on its appeal to the Superior Court of New Jersey in response to the
BPU's Decision and Order dated April 24, 1996 on ACE's 1995 LEC Petition. In
its brief, RISC argues that the BPU did not follow the rules of the FERC as
required by the PURPA in its approval of the NUG contracts. Also, RISC argues,
the stipulation approving the methodology by which the NUG contracts are
priced was approved by the BPU without public notice or opportunity for public
hearings. RISC argues that the BPU should order a hearing to reconsider the
contracts, recalculate the contract prices and give the public the opportunity
to participate in the hearings. RISC further argues that ACE's
7
customers should not pay for the above current market costs of these NUG
contracts and that ACE should not be permitted to recover costs relating to
the maintenance of excess capacity. RISC has calculated the above market cost
of the NUG contracts to be $132.574 million and the excess capacity costs to
be $11.169 million. Thus RISC is recommending that ACE's rates be reduced by
$143.743 million. On July 14, 1997 ACE submitted its reply brief in the RISC
appeal to the Appellate Division of the Superior Court of New Jersey. It is
the position of ACE, that in this LEC proceeding, the BPU made proper findings
with regard to the level of allowable expenses for fuel and purchased power.
ACE argues that the recoverability of payments made to Qualifying Facilities
(QFs) was already established in previous, final BPU determinations. Such
determinations were made in accordance with the PURPA and the rules and
regulations promulgated by the FERC. As such, it is the position of ACE that
the BPU properly addressed the arguments raised by RISC and properly rejected
the attempt by RISC to have the BPU disallow QF expenses in this regard. At
this time, RISC has not submitted a reply to the ACE's brief and ACE cannot
predict the outcome of this matter.
On August 1, 1997 ACE filed a request for $6.8 million increase in annual
base revenues for the recovery of other post-retirement benefits (OPEB)
expenses. In October 1997, ACE amended its filing to request an increase in
annual base rate revenues of $8.4 million for the recovery of OPEB expenses.
The amended amount was the result of changes to the 1997 Gross Receipts and
Franchise Tax (GR&FT) legislation. (See Note 2 of the Notes to the
Consolidating Financial Statements for further information on the GR&FT.)
At its December 30, 1997 agenda meeting, the BPU approved a rate increase of
$5.025 million effective January 1, 1998 for the recovery of OPEB expenses.
Also, in a related action the BPU approved the request for a change of
ownership and found that an annual rate decrease of $15.750 should be provided
to ACE's customers effective with the closing of the merger. The BPU then
ordered, effective January 1, 1998, a premerger credit of $5.025 million from
the annual merger savings to offset the increase required for the recovery of
OPEB rates. (For more information regarding ACE's LEC filings see Note 3 of
the Notes of the Consolidating financial statements.)
DEMAND SIDE MANAGEMENT
ACE submitted its second Demand Side Management (DSM) Plan for the period
from September 1997 through August 1998 in April 1997. The DSM Plan includes
programs which address energy conservation needs of the residential,
commercial and industrial markets but are not intended to promote new uses of
electricity. Motions were filed on behalf of interveners who were granted full
intervenor status by the BPU on July 30, 1997. During the course of the DSM
proceedings, the Ratepayer Advocate alleged that ACE has been recovering more
in rates for DSM purposes than it is spending. The interveners, the BPU (the
Parties) and ACE have come to an agreement on the terms of the Plan except
with regard to the overrecovery issue. On March 10, 1998 ACE filed a
reconciliation of the DSM programs with the BPU, pursuant with N.J.A.C. 14:12
(Docket No. EE97050334). The purpose of this filing was to detail the level of
DSM expenditures for the period calendar years 1994 through 1997. It is ACE's
position that the level of DSM expenditures cannot be viewed in isolation, but
must be considered in light of both the overall history of DSM expenditures
under current rates, as well as ACE's overall revenue requirement needs in a
rate proceeding. As of the date of this filing responses from the Parties have
not yet been received. Upon their receipt the matter will then be submitted to
the BPU for review. At this time ACE is unable to determine the probable
outcome of this matter.
ENERGY REQUIREMENTS AND POWER SUPPLY
ACE's 1997 kilowatt-hour sales decreased by approximately 0.6% over 1996
sales. Residential sales declined 3.7%; commercial sales grew 1.3%; and,
industrial sales grew 3.2%. The 1997 Utility System Peak
8
demand of 2,064 MWs occurred on August 16, 1997 and was 1.1% above the
previous peak demand recorded on July 10, 1995 of 2,042 MWs.
For the five year period beginning in 1998, ACE's estimate of projected
compound annual sales growth is 3.9%, and peak load growth (weather adjusted)
is 2.8%. Sales growth for the five year forecast period reflects the on-going
and anticipated expansion of the Atlantic City casino-hotel and entertainment
industries and the associated spin-off effects of stronger labor and housing
markets in the region. ACE's energy sales forecast quantifies the expected
consumption in ACE's traditional franchise area and does not reflect any
potential developments regarding open retail access to competitive energy
markets. ACE's forecast is adjusted for the effects of demand-side management
programs, customer-initiated energy efficiency improvements and customers
taking service under off-tariff rates.
ACE has generally been able to provide for the growth of energy requirements
through the capacity purchases from other utilities and nonutilities, joint
ownership in larger units and construction of additional generating capacity.
ACE's net summer installed capacity, at December 31, 1997, consisted of the
following:
YEAR(S) NET
STATION AND PRIMARY UNIT(S) CAPABILITY
LOCATION FUELS INSTALLED (MW)
----------- ------- --------- ----------
Deepwater Salem Co., N.J............... Oil/Coal/Gas 1930/ 54.0
1954-1958 166.0
B.L. England Cape May Co., N.J......... Coal/Oil 1962-1964/ 284.0
1974 155.0
Keystone Indiana Co., PA............... Coal 1967-1968 42.0(1)
Conemaugh Indiana Co., PA.............. Coal 1970-1971 65.0(1)
Peach Bottom York Co., PA.............. Nuclear 1974 164.0(1)
Salem Salem Co., N.J................... Nuclear 1977-1981 164.0(1)
Hope Creek Salem Co., N.J.............. Nuclear 1987 52.0(1)
Combustion Turbine Units (various loca-
tions)................................ Oil/Gas 1967-1991 524.0
Diesel Units........................... Oil 1961-1970 8.7
Firm Capacity Purchases and Sales --
Net.................................. 737.0(2)
-------
Total Generating Capability.......... 2,415.7
=======
- --------
NOTES
(1) ACE's share of jointly-owned stations. (See Note 6 of AEI's Notes to
Consolidated Financial Statements.)
(2) Primarily consists of 125 MW from thirteen coal-fired units of PP&L and
612 MW from four nonutility suppliers.
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. (See Note 6 of the Notes to Financial Statements
for additional information regarding capital and operating expenses of ACE's
jointly-owned nuclear facilities.)
POWER POOL AND INTERCONNECTION AGREEMENTS
ACE is a member of the Pennsylvania-New Jersey-Maryland Interconnection
Association (PJM), an integrated power pool which coordinates the bulk power
supply of eight electric utility companies in Pennsylvania, New Jersey,
Delaware, Maryland, Virginia and the District of Columbia, and is
interconnected with other major utilities in the northeastern United States.
The member utilities coordinate generation/supply planning and own and control
the bulk power transmission system in the region. As a member of PJM, ACE is
required to plan for reserve capacity based on estimated aggregate PJM
requirements allocated to member
9
companies. ACE periodically files its capacity addition plans with PJM which
are intended to meet forecast capacity and reserve obligations. 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. PJM
currently operates on the basis of reliability of service and operating
economy whereby generating units are subject to central dispatch, from order
of lowest operating cost to highest cost.
In July 1996, ACE, together with other regional Mid-Atlantic utilities,
filed with the FERC, a restructuring plan designed to meet the FERC
requirements of Order 888 to functionally unbundle transmission services and
to establish a new wholesale energy market. The plan proposed to 1) create an
independent system operator, a nonprofit corporation with an independent board
of directors, to manage the PJM Power Pool's energy market and transmission
operation; 2) establish a spot-energy market open to any buyer or seller and
provide utilities, nonutility power generators and wholesale energy brokers
comparable pool-wide transmission service; 3) provide for bilateral energy
arrangements, and 4) allow load-serving entities within the PJM control area
to share generating capacity reserves and provide mutual assistance during
emergencies.
On February 28, 1997, FERC issued an order approving the implementation of
the restructuring proposed by the majority of the PJM companies, on an interim
basis, with minor exceptions. The "interim market" was initiated on April 1,
1997 without formal ISO recognition or locational pricing. Subsequent to a
technical conference and meeting with the PJM stakeholders, another proposal
was submitted to the FERC on June 2, 1997 requesting ISO status for the PJM
office of the Interconnection, and further defining the request for locational
pricing for transmission congestion management. On November 25, 1997 the FERC
approved the proposal with minor revisions. The majority of the new changes
were put in place on January 1, 1998. Minor changes to the tariff and the
congestion pricing plan were deferred until April 1, 1998. The transmission
and energy agreements and markets are operating as predicted.
POWER PURCHASES AND SALES
ACE is currently purchasing 125 MW of capacity and energy from PP&L coal-
fired sources. By a letter dated March 16, 1995, the Company notified PP&L
that this capacity and energy sales agreement will be terminated effective
March 1998. To replace the PP&L arrangement, the Company has signed a letter
of intent with PECO Energy (PE) for the purchase of 125 MWs of capacity and
energy for the period beginning March 16, 1998 through May 31, 2000. A second
agreement with PE, subject to the approval of the BPU, arranges for the
purchase of 175 MWs of capacity and energy beginning in June 1999 through May
2009. 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.
BULK POWER MARKETING
As a result of the developing wholesale bulk power market, in 1996, ACE
applied to, and was approved by, the FERC to trade wholesale electric power in
the United States. In the course of this business, ACE enters into commitments
to buy and sell power. At January 31, 1998, ACE has conducted approximately
1.1 million MWhrs of energy transactions to unaffiliated companies for 1998.
As of January 31, 1998, ACE has unhedged outstanding agreements to sell 88,000
MWhrs of energy to unaffiliated companies. These sales result in commitments
of approximately $2.48 million through 1998. The duration of each of these
contracts does not exceed one month.
CAPACITY PLANNING
The Electric Facilities Need Assessment Act (EFNAA) requires public
utilities in the State of New Jersey to obtain a Certificate of Need (CON)
prior to constructing (1) any electric power generating unit or combination of
units at a single site with a combined capacity of 100 MW or more or (2) any
electric generating units added to an existing generating facility which will
increase its installed capacity by 25% or by more than 100 MW,
10
whichever is smaller. In addition, New Jersey utilities are required to comply
with a stipulation of settlement approved by the BPU in July 1988 the purpose
of which 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 nonutility sources.
The stipulation of settlement referred to above was due to expire on
September 15, 1993. 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. The most recent ACE filing indicated that ACE did
not require additional capacity until 2000 when the need would be met with
combined cycle units and/or power purchases.
The ongoing outage of the Salem Unit 1 has required ACE to secure additional
capacity, sufficient to meet PJM reserve requirements. Assuming the return of
the unit in 1998, ACE's installed capacity and capacity purchase arrangements
for 1998-1999 are expected to be sufficient to supply its share of PJM reserve
requirements during that period. 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.
ACE's Capacity Planning will depend upon factors such as long-term load,
customer growth, the effects of competition and retail wheeling and the issues
of basic generation service and Demand Side Management Programs, and the BPU's
findings and recommendations on restructuring the electric power industry in
New Jersey.
NONUTILITY GENERATION
Additional sources of capacity for use by ACE are made available by NUG
sources, principally cogenerators. ACE currently has four, BPU-approved power
purchase agreements for the purchase of capacity and energy from NUG sources
under the standard offer methodology developed and approved by the BPU in
August 1987 and as previously discussed.
MW DATE OF
PROJECT LOCATION FUEL TYPE PROVIDED COMMERCIAL OPERATION
---------------- --------- -------- --------------------
Chester, Pennsylvania.............. solid waste 75 September 1991
Pedricktown, New Jersey............ gas 116 March 1992
Carney's Point, New Jersey......... coal 188 March 1994
Logan Township, New Jersey......... coal 200 September 1994
---
Total............................ 579
===
Amendments to the agreements between ACE and the sponsors of the Logan and
Pedricktown facilities have restructured ACE's payment for capacity and energy
reducing the energy component of such payments. The amendment to the agreement
between ACE and the sponsors of the Pedricktown facility, which includes an
affiliate of ACE, also increased the available capacity of the facility from
106 MW to 116 MW and returned the project's thermal host to ACE as a retail
customer effective November 1995.
NUCLEAR GENERATING STATION DEVELOPMENTS
ACE is a joint owner of the Hope Creek and Salem Nuclear Generating
Stations, to the extent of 5% and 7.41%, respectively.
11
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 (PS).
ACE is also a joint owner of 7.51% of Peach Bottom Atomic Power Station
Units 2 and 3, which are located in York County, Pennsylvania and are operated
by PECO Energy (PE). (See Note 6 of AEI's Notes to Consolidated Financial
Statements for additional information relating to the Company's investment in
jointly-owned generating stations.)
In 1997, nuclear generation provided 18% of ACE's total energy output. The
approximate capacity factors (based on maximum dependable capacity ratings)
for ACE's jointly-owned units for 1996 and 1997 were as follows:
UNIT 1997 1996
---- ---- ----
Salem Unit 1................................................... 0.0% 0.0%
Salem Unit 2................................................... 25.5% 0.0%
Peach Bottom Unit 2............................................ 98.6% 79.8%
Peach Bottom Unit 3............................................ 78.0% 98.2%
Hope Creek..................................................... 52.4% 74.6%
See "Salem Station" below for additional information on operating performance
at Salem.
ACE has been advised that the Nuclear Regulatory Commission (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
PE has informed the NRC that it has taken short-term corrective 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
PE's interim actions were acceptable. PE has advised ACE that PE has been in
contact with the NRC regarding PE's long-term measures to address Thermo-Lag
fire barrier issues. In 1995, PE completed its engineering re-analysis for
Peach Bottom. The re-analysis identified proposed modifications to be
performed over the next several years in order to implement the long-term
measures addressing the concern over Thermo-Lag use. ACE has been advised that
PE plans to complete all necessary corrective actions by the end of the 1999
Unit 3 refueling outage.
As previously reported on Form 10-K for 1996, in 1990 General Electric (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. PS, the operator of the Hope Creek, is participating in the
GE BWR Owners Group to evaluate this issue and develop long-term corrective
action. During its 1994 refueling outage, PS inspected the shroud of Hope
Creek in accordance with GE's recommendations and found no cracks. In June
1994, an industry group was formed and subsequently established generic
inspection guidelines which were approved by the NRC. Hope Creek was initially
placed in the lowest susceptibility category under these guidelines. ACE has
been advised that due to Hope Creek's operating time, it now falls into the
intermediate susceptibility category. PS also advised ACE that another
inspection was performed by PS during Hope Creek's latest refueling outage in
September 1997. The inspection disclosed no indications of cracking in the
accessible areas of the four welds examined.
PE has advised ACE that Peach Bottom Unit 2 was reinspected during its 1996
refueling outage. While additional minor flaw indications were discovered,
neither repair nor modification to the core shroud was necessary prior to
restarting the reactor. PE has also advised that examinations of the Peach
Bottom Unit 3 core shroud was not required during its 1997 refueling outage
and that an examination will be performed during its next refueling outage in
1999.
12
In a separate matter, PS has advised that as a result of several BWRs
experiencing clogging of some emergency core cooling system suction strainers,
which supply water from the suppression pool for emergency cooling of the core
and related structures, the NRC issued a Bulletin in May 1996 to operators of
BWRs requesting that measures be taken to minimize the potential for clogging.
The NRC has proposed three resolution options and required that actions be
completed by the end of the units first refueling outage after January 1997.
Alternative resolutions options will be subject to NRC approval. PS has
advised ACE that PS has installed a portion of the required large capacity
passive strainers at Hope Creek during Hope Creek's latest refueling outage.
On October 31, 1997, the NRC permitted PS to defer installation of the
remaining strainers until the next refueling outage, currently scheduled for
February 1999. PE has advised ACE that large capacity passive strainers were
installed in Peach Bottom Unit 3 during its October 1997 refueling outage and
that it is preparing to install new strainers in Peach Bottom Unit 2 during
its October 1998 refueling outage. ACE, PE or PS cannot predict what actions,
if any, the NRC may take in this matter.
PS and PE have advised ACE that in October 1996, PS & PE, along with other
nuclear plant owners, received a request for information regarding the
adequacy and availability of each plant's design bases data. The NRC is
requiring that information be submitted under oath and affirmation to provide
it added confidence and assurance that all nuclear units are operated and
maintained within the design bases of the facilities and that any deviations
have been or will be reconciled in a timely manner. PS advised ACE that PS
responded to the NRC's request on February 11, 1997 with a detailed
description of ongoing activities and new initiatives to ensure that Salem and
Hope Creek are operated and maintained within their design bases. PE provided
a similar response to the NRC on February 4, 1997 concerning Peach Bottom.
Since the information which was submitted will be used by the NRC to determine
follow-up inspection activity or potential enforcement actions, neither ACE,
PE, nor PS, can predict at this time what impact the NRC's request will have.
PS and PE have advised ACE that On January 29, 1998, the NRC proposed to
issue a generic letter which would require all nuclear plant operators to
provide the agency with information concerning their programs, planned or
implemented, to address Year 2000 computer and systems issues at their
facilities. In particular, operators would be asked to provide confirmation of
implementation of their programs and certification that their facilities are
Year 2000 ready and in compliance with the terms and conditions of their
licenses and NRC regulations. Licensees would be required to submit a written
response indicating the status of their Year 2000 readiness program including
scope, assessment process and plans for corrective action. Further, upon
completion of their Year 2000 readiness program and no later than July 1,
1999, licensees would be required to confirm to the NRC that their facility is
Year 2000 ready, together with a status report of work necessary to be Year
2000 compliant. Year 2000 ready means computer systems and applications are
suitable for continued use into 2000. Year 2000 compliant means that such
systems and applications accurately process date/time data beyond 2000.
Neither ACE, PE nor PS can predict if this or any proposal will be adopted by
the NRC.
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 (Plant Support 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.
SALEM STATION
ACE is a 7.41% owner of Salem Nuclear Generating Station (Salem) operated by
PS. Salem consists of two 1,106 MW pressurized water nuclear reactors (PWR)
representing 164 MWs of ACE's total installed capacity of 2,415.7 MW.
As previously reported, Salem Unit 1 has been out of service since May 16,
1995. PS has advised ACE that the installation of Salem Unit 1 four steam
generators has been completed. The cost of purchasing and installing the steam
generators, as well as the disposal of the old generators is $186 million, of
which ACE's share is $13.8
13
million. All four of the original generators have been removed from the
containment structure and have been shipped offsite for disposal at the
Barnwell, South Carolina low-level radioactive waste burial facility. The unit
is currently expected to return to service in the second quarter of 1998.
Restart of Salem Unit 1 is subject to completion of the requirements of the
restart plan to the satisfaction of PS and the NRC. The company has been
informed by PS that the NRC's Readiness Assessment Team Inspection (RATI) of
Salem Unit 1 (a requirement for restart) was completed on February 20, 1998.
The inspection team concluded that Salem Unit 1 was ready to return to
operation.
ACE has been advised by PS that Salem Unit 2, out of service since June 7,
1995, was returned to service on August 30, 1997 and reached 100% power on
September 23, 1997. The NRC required a Final Assessment of Unit 2 after
approximately two months of full power Operation. On December 4, 1997 a
meeting was held with PS and the NRC which satisfied this final requirement
for Unit 2.
During the course of these outages, PS has also been required to address
certain generic issues applicable to nuclear power plants, which have also
affected the length of the outages. ACE was advised by PS that a Generic
Letter from the NRC identified an issue that impacted the Salem Unit 2 startup
schedule. This Generic Letter (96-06) requested all nuclear utilities,
including PS, to review systems for potential waterhammer events (hydrodynamic
stress caused by steam formation in a piping system) and the impact that these
events could have on the system's safety function. Modifications which address
the implications of 96-06 have been completed at both Salem Units 1 and 2.
PS advised ACE that in January 1997 the NRC held a semi-annual Senior
Management Meeting. At that meeting the NRC held a public meeting and
identified Salem Units 1 and 2 as Category 2 plants placed on the "NRC Watch
List" noting that this action was not due to any performance problems or
decline during its current evaluation period but rather that Salem should have
been placed on the NRC Watch List earlier. Plants in this category have been
identified as having weaknesses that warrant increased NRC attention until the
licensee demonstrates a period of improved performance. In their letter the
NRC stated that the staff was satisfied with the overall approach being taken
by PS to return the Salem Units to service. Salem Units 1 and 2 remain on the
NRC Watch List as a Category 2 plant until the licensee either demonstrates a
period of improved performance, or until a further deterioration of
performance results in the plant being placed in Category 3. A Category 1
facility is a plant that has been removed from the Watch List.
As previously reported in the 1996 Form 10-K, the Salem co-owners filed a
Complaint in February 1996 in the United States District Court for the
District of New Jersey against Westinghouse Electric Corporation, the designer
and manufacturer of the Salem steam generators, seeking damages to recover the
cost of replacing the steam generators at Salem Unit 1 and 2. In accordance
with the court's schedule, Westinghouse filed a motion for summary judgment on
October 1, 1997. Also in accordance with the court's schedule, ACE and the
three co-owners of Salem will file their opposition to that motion for summary
judgement. Oral arguments on this motion were held in February 1998. A
decision is anticipated within approximately 30 days after the competition of
the oral arguments. ACE cannot predict the outcome of this proceeding.
On July 8, 1997, a predecisional enforcement conference was held with the
NRC to discuss apparent violations at Salem. These apparent violations were
identified in May and June, 1997, and concern emergency core cooling system
switchover and related residual heat removal system (RHR) flow issues, and
Appendix R (fire protection) issues. PS has advised ACE that, in a letter
dated October 8, 1997, the NRC informed PS that a Level III violation was
cited for the issues surrounding the RHR system and Level IV violations were
cited for the two Appendix R issues. There was no civil penalty issued by the
NRC.
PS has advised ACE that it is implementing the 1994 New Jersey Pollutant
Discharge Elimination System permit issued for Salem which requires, among
other things, water intake screen modifications and wetlands restoration. In
addition, PS is seeking final permits and approvals from various agencies
needed to fully implement the special conditions of the permit. No assurances
can be given as to receipt of any such additional permits or approvals. In
1999, PS must apply to the New Jersey Department of Environmental Protection
and other agencies to renew such Salem permits.
14
For information concerning 1) the BPU's 1996 investigation into the Salem
outage, 2) capital, operations and maintenance costs associated with Salem
Units 1 and 2, and 3) the effects of the Salem outage on operations, see Notes
6 and 11 of the Company's Consolidated Financial Statements and Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Results of Operations, respectively.
HOPE CREEK STATION
ACE is a 5% owner of Hope Creek Nuclear Generating Station (Hope Creek)
which is operated by PS.
PS advised ACE that Hope Creek completed its latest planned refueling and
maintenance outage in December 1997.
ACE has also been advised that a predecisional enforcement conference was
held with the NRC on August 12, 1997, to discuss apparent violations at Hope
Creek relating to the installation of cross-tie valves in the residual heat
removal system at Hope Creek in 1994. On October 20, 1997, the NRC issued a
severity level III violation for this matter. There was no civil penalty
issued by the NRC for this violation.
PS has also advised ACE that a predecisional enforcement conference was held
on December 9, 1997 to discuss two allegations concerning security program
issues which occurred at Salem and Hope Creek in 1996. Neither ACE or PS
cannot predict what other actions, if any, the NRC may take in these matters.
PS also advised ACE that two predecisional enforcement conferences for Hope
Creek were held on January 14, 1998 to discuss two apparent violations
concerning implementation of the Maintenance Rule and one apparent violation
concerning control rod operation. On March 23, 1998, PS advised ACE that in a
letter from the NRC these two issues at Hope Creek resulted in two Level III
violations and an associated $55,000 civil penalty. The first issue was
identified at an inspection in November 1997, while the unit was shut down for
normal refueling maintenance. The NRC inspectors were monitoring a special
test required prior to startup. The operators completed the test evolution
without incident; however, the NRC noted that certain plant conditions
required more strict procedure compliance and management oversight than was
provided. This resulted in one of the two Level III violations and the civil
penalty. The NRC issued the civil penalty because a similar issue had been
identified in 1996. The second issue concerned the implementation of the
Maintenance Rule, which requires utilities to monitor the effectiveness of
equipment reliability. The NRC said that PS's Maintenance Rule program did not
include all necessary equipment. Because this issue was self-identified and
immediate corrective actions taken, the NRC issued a Level III violation with
no civil penalty.
PEACH BOTTOM STATION
ACE is a 7.51% owner of Peach Bottom Atomic Power Station (Peach Bottom)
operated by PE. Unit 3 successfully completed a scheduled refueling and
maintenance outage in November 1997.
PE has advised ACE that on July 17, 1997, the NRC issued its periodic SALP
Report for Peach Bottom for the period October 15, 1995 to June 7, 1997. Peach
Bottom achieved ratings of "1", in the areas of Operations, Maintenance and
Plant Support. The area of Engineering achieved a rating of "2". Overall, the
NRC observed excellent performance at Peach Bottom during the assessment
period. PE has advised ACE that the NRC stated that station management
provided excellent oversight and control of engineering activities throughout
the period. The NRC noted that, while overall engineering performance was
good, there were several instances where operating procedures, surveillance,
and tests were not consistent with the design and licensing bases. PE has
advised ACE that it will continue to take actions to improve performance at
Peach Bottom.
ACE has been advised by PE that crack indications were discovered in three
of the ten recirculation system jet pump riser pipes, located inside the
reactor vessel, on Peach Bottom Unit 3 during the October 1997 refueling
outage. PE has developed a plan allowing for the continued operation of the
unit for several months while a permanent repair was developed. The plan
limits operation of the unit to 94% of its rated power level for most
15
his period. PE removal Peach Bottom Unit 3 from service on March 13, 1998 to
perform repairs which are expected to return the unit to full power operation.
FUEL SUPPLY
ACE's sources of electrical energy (including power purchases) for the years
indicated are shown below:
SOURCE 1997 1996 1995
------ ---- ---- ----
Coal........................................................ 26% 28% 33%
Nuclear..................................................... 18% 15% 19%
Oil/Natural Gas............................................. 3% 2% 3%
Interchange and Purchased Power............................. 30% 35% 21%
Nonutility.................................................. 23% 20% 24%
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, 2000. See
"Environmental Controls -- Air" for information concerning the use of
particular fuels at B. L. England Station.
On December 31, 1997, the oil supply at Deepwater Station was sufficient to
operate Deepwater Unit 1 for 21 days, and the supply at B. L. England Station
was sufficient to operate Unit 3 for 53 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, 1997,
the coal inventory at the B. L. England Station was sufficient to operate
Units 1 and 2 for 71 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, 2001. On December 31, 1997, the coal
inventory at Deepwater Station was sufficient to operate Unit 6/8 for 171
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
16
these contracts, coal supplies are obtained from local suppliers. As of
December 31, 1997, Keystone and Conemaugh had approximately a 29-day supply
and a 35-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 the local distribution
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 gas, conversion of the enriched gas to fuel pellets and
fabrication of fuel assemblies. ACE has been advised that PS has several long-
term contracts with uranium ore operators, converters, enrichers and
fabricators to process uranium ore to uranium concentrate to meet the
currently projected requirements for the Salem and Hope Creek units. ACE has
also been advised that PE has similar contracts to satisfy the fuel
requirements of Peach Bottom Units 2 and 3. Currently, there is an adequate
supply of nuclear fuel for Salem, Hope Creek and Peach Bottom.
ACE has been advised by PE, operator of the Peach Bottom units, that it has
contracts for uranium concentrates to fully operate Peach Bottom Units 2 and 3
through 2002. ACE has been advised that PE does not anticipate any
difficulties in obtaining its requirements for uranium concentrates. PE
advises that its contracts for uranium concentrates will be allocated to the
Peach Bottom units, and other PE nuclear facilities in which ACE has no
ownership interest, on an as-needed basis.
PE has reported contracts for the following segments of the nuclear fuel
supply cycle with respect to each of the joint-owned units through the
following years:
NUCLEAR UNIT CONVERSION ENRICHMENT FABRICATION
------------ ---------- ---------- -----------
Peach Bottom Unit 2...................... (1) (2) 2001
Peach Bottom Unit 3...................... (1) (2) 2002
- --------
(1) 100% of conversion services for Peach Bottom through 2001 and at least 60%
of the conversion services requirements are covered through 2002. PE does
not anticipate any difficulty in obtaining necessary conversion services
for Peach Bottom.
(2) Contractual commitments for enrichment services for Peach Bottom with the
United States Enrichment Corporation represent 100% of the enrichment
services through 2004. PE does not anticipate any difficulty in obtaining
necessary enrichment services for Peach Bottom.
NUCLEAR FUEL DISPOSAL
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.
The Federal government's present policy is that spent nuclear fuel will be
accepted for storage and disposal at government-owned and operated
repositories. However, at present there are no such repositories in service or
under construction. PE currently stores all spent nuclear fuel from its
nuclear generating facilities in on-site,
17
spent-fuel storage pools. Spent-fuel racks at Peach Bottom have storage
capacity until 2000 for Unit 2 and 2001 for Unit 3, prior to losing full core
discharge reserve capability. PE has advised ACE that it is constructing an
on-site dry storage facility which is expected to be operational in 2000 to
provide additional storage capacity. ACE has been advised by PS that as a
result of reracking the two spent-fuel pools at Salem, the spent-fuel storage
capability of Salem Units 1 and 2 is estimated to be 2012 and 2016,
respectively, prior to losing an operational full core discharge reserve. The
Hope Creek pool is also fully racked and it is conservatively expected to
provide storage capacity until 2006, again prior to losing an operational full
core discharge reserve. (See Note 14, Leases, of the Notes to Consolidated
Financial Statements for financing arrangements for nuclear fuel.)
In conformity with the NWPA, PS and PE, on behalf of the co-owners of the
Salem and Hope Creek, and Peach Bottom stations, respectively, have entered
into contracts with the U.S. 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 DOE was to begin accepting spent fuel for permanent offsite
storage no later than 1998, but such storage may be delayed indefinitely. ACE
has been advised by PS and PE that the DOE has stated that it would not be
able to open a permanent, high-level nuclear waste storage facility until
2010, at the earliest. However, the DOE has also indicated that progress on
the repository would be delayed beyond 2010 if sufficient funds, though
available in the Nuclear Waste Fund, are not appropriated by the Congress for
this program. Accordingly, legislation which would have the DOE establish a
centralized interim spent fuel storage facility has been introduced in
Congress. In cases brought by several utilities and many state and local
governments, the United States Court of Appeals for the District of Columbia
Circuit reaffirmed DOE's unconditional obligation to begin spent fuel
acceptance by January 31, 1998. In November 1997, the court ruled that the
utilities had fulfilled their obligations under their respective contracts
with DOE by contributing to the Nuclear Waste Fund. The court further ruled
that DOE's argument of unavoidable delay to meet its obligation was without
merit. However, the court did not order DOE to commence spent fuel acceptance
by January 31, 1998; instead, it decided that the standard contract provided a
potentially adequate remedy in the form of payment of damages if DOE failed in
its obligations. PS also advised ACE that PS is working with the utility
industry to develop a methodology for determining damages incurred as a result
of DOE's failure to meet its obligation and a strategy for its implementation.
The decision of the Court of Appeals has been appealed to the U.S. Supreme
Court by the U.S. Department of Justice. No assurances can be given as to the
ultimate availability of a facility.
NUCLEAR DECOMMISSIONING
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 $4.6 million
and a related regulatory asset of $5.0 million for such costs at December 31,
1997. ACE made its first payment related to this liability to the respective
operating companies in September 1993 and continues to make payments as
required. 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.
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. N.J.A.C. 14:5A-2.1
requires that all New Jersey electric utilities file with the BPU a nuclear
decommissioning cost update by January 1, 1996 and every four years
thereafter.
18
In January 1996, PS and ACE jointly filed with the BPU its 1995 Nuclear
Decommissioning Cost updates. ACE and PS filed NRC cost estimates for each of
their five jointly-owned nuclear units based on the NRC's existing generic
formula. ACE and PS do not believe that these NRC generic estimates provide an
accurate estimate of the cost of decommissioning the nuclear units, but
believe these costs are best estimated with periodic site-specific studies.
PS, on behalf of the co-owners of the Salem, Hope Creek and Peach Bottom
stations, engaged an independent engineer to undertake such site specific
studies. In September 1996, these studies were submitted to the BPU for review
by the Staff of the BPU and the Ratepayer Advocate. The studies support the
current level of funding and, as such, ACE will not seek to increase the
recovery of decommissioning in its rates. 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, will remain at $6.4 million annually. (See Note
11 Commitments and Contingencies of the Notes to Consolidated Financial
Statements for information relating to decommissioning of the five nuclear
units in which ACE has an ownership interest.)
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 and 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.
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 produce
substantial amounts of low-level radioactive waste (LLRW). Such waste is
presently accumulated on-site and permanently disposed of at a federally
licensed disposal facility. ACE had been advised by both PE and PS that LLRW
generated at Peach Bottom, Salem and Hope Creek is shipped to the site located
in Barnwell, South Carolina for disposal. Due to the uncertainty of the
continued availability of LLRW disposal sites, on-site storage facilities were
constructed at Peach Bottom with a five-year storage capacity. PS advises that
it also has an on-site LLRW storage facility at Salem also with a five-year
storage capacity. PS has advised ACE that New Jersey planned to host a LLRW
disposal site by the year 2000. Public meetings have been held across the
State to provide information to and obtain feedback from the public. To date,
there have been no voluntary sites identified. Consequently, on February 10,
1998, the State agency responsible for this program recommended to the
Governor that this effort be abandoned.
PE has advised ACE that PE is pursuing alternative disposal strategies for
LLRW generated at Peach Bottom including an aggressive LLRW reduction program.
Pennsylvania is the host site for LLRW generators located in Pennsylvania,
Delaware, Maryland and West Virginia and is pursuing a permanent disposal site
through a volunteer siting process.
19
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.
For information regarding ACE's nuclear power replacement cost insurance and
liability under the Federal Price-Anderson Act, see Note 11 of the Notes to
Consolidated Financial Statements, herein.
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 U.S. Environmental Protection Agency (EPA) relating to the
generation and temporary storage 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
20
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's contribution to-date for the
remediation and clean-up of the Atlantic County site has been approximately
$300,000. It is not anticipated that future contributions, if any, will be
significant.
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. ACE's
contribution to date for the remediation and clean-up of the Gloucester County
site has been $105,000. It is not anticipated that future contributions, if
any, will be significant.
On November 26, 1997, ACE received a letter from the U.S. EPA requesting
information pursuant to 42 U.S.C.9604(E) for a site identified in Newark, New
Jersey and was to provide a response to the EPA under CERCLA Section 104(e).
On January 21, 1998, ACE responded to the request for information. In summary,
ACE identified transactions that were limited exclusively to the purchase of
reconditioned storage drums from a third party and did not transact any
business involving the disposal, treatment, or storage of any containers,
barrels or drums. As a result, ACE is not a responsible party at the site. ACE
cannot predict what action, if any, the EPA may take in this matter.
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 amendments
to the CAFRA regulations expanded the area under CAFRA control as well as the
types of developments subject to CAFRA. The current regulations provide
exemptions for the maintenance and repair of existing electrical substations,
but are not clear as to whether a CAFRA permit would be required for
construction, maintenance and/or repair of transmission lines within the CAFRA
area.
21
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 (CORP) is considering promulgation of regulations which would
authorize the NJDEP to review all new power line projects of 100 kilovolts or
more. While 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, current discussions with CORP indicate that such regulations
would not significantly impact ACE's operations. 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 1998-2000 estimated
construction expenditures.
Statement of Position of the Accounting Standards Board 96-1 "Environmental
Remediation Liabilities" (SOP 96-1) was effective for fiscal years that begin
after December 15, 1996. SOP 96-1 provides guidance where remediation is
required because of the threat of litigation, a claim or an assessment. This
Statement does not provide guidance on accounting for pollution control costs
as it applies to current operations, costs of future site restoration or
closure that are required upon the cessation of operations or sale of
facilities or for remediation obligations undertaken at the sole discretion of
management. The adoption of SOP 96-1 did not have a material impact on the
financial position, results of operations or net cash flows of the Company.
Air
The NJDEP is using the New Jersey Administrative Code, Title 7, Chapter 27
(NJAC 7:27) as its State Implementation Plans (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 mandated 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. 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, were
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.
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. NJDEP regulations
adopted in November 1993 require that a compliance plan be filed with the
NJDEP. ACE's compliance plan, filed April 22, 1994, and subsequent amendments,
have been accepted by the NJDEP. Preliminary capital expenditures are
estimated at $9.8 million over the next five years 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.
On August 1, 1997, the New Jersey Department of Environmental Protection
(NJDEP) announced that it intends to introduce rules to reduce NOx emissions
by 90% from the 1990 levels by the year 2003. These rules have not yet been
promulgated. On September 15, 1997 the NJDEP filed its proposal with the
Office of Administrative Law. In its proposal, entitled "NOx Budget Program",
N.J.A.C. 7:27-31, the NJDEP prescribed
22
participation of New Jersey's large combustion sources in a regional cap and
trade program designed to significantly reduce emissions of NOx. In effect,
the proposed regulation would require New Jersey to become the first
northeastern state to require NOx reductions of 90% from the 1990 levels, by
the year 2003. On October 24, 1997 ACE testified in opposition to the
proposal. ACE cannot predict the ultimate outcome of this matter.
On January 23, 1997, the EPA issued Compliance Order 113-97-001 (Order) for
failure to comply with emission monitoring requirements on a combustion
turbine unit at the Sherman Avenue Generating Station. The Order carries a
potential penalty of $25,000 a day, retroactive to May 30, 1991. On June 19,
1997 ACE completed all actions specified in the Order within the time limits
set forth in the Order and believes it is in full compliance with all
applicable requirements. At this time ACE does not anticipate any further
action by the EPA in this matter.
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 NJPDES 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. Deepwater Station was issued a
preliminary draft NJPDES permit in January 1998. ACE is currently reviewing
the preliminary draft permit.
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 was denied in the preliminary draft permit. ACE is currently
evaluating its options regarding continuing to contest this issue. 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. The ground water discharge permit for B. L.
England Station was renewed effective June 7, 1996.
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
23
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 1997 amounted to $14.7 million, and its most
recent estimate for such compliance for the years 1998-2000 is $10.6 million.
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. (See Note 11 of the Notes to Consolidated Financial Statements
for further information.)
ITEM 2 PROPERTIES
Under New Jersey law, the State of New Jersey owns in fee simple for the
benefit of the public schools all lands now or formerly flowed by the tide up
to the mean high-water line, unless it has made a valid conveyance of its
interests in such property. In 1981, because of uncertainties raised as to
possible claims of State ownership, the New Jersey Constitution was amended to
provide that lands formerly tidal-flowed, but which were not then tidal-flowed
at any time for a period of 40 years, were not to be subject to State claim
unless the State has specifically defined and asserted a claim within one year
period ending November 2, 1982. As a result, the State published maps of the
eastern (Atlantic) coast of New Jersey depicting claims to portions of many
properties, including certain properties owned by the Company. The Company
believes it has good title to such properties and will vigorously defend its
title, or will obtain such grants from the State as may ultimately be
required. The cost to acquire any such grants may be covered by title
insurance policies. Assuming that all of such State claims were determined
adversely to the Company, they would relate to land, which, together with the
improvements thereon, would amount to less than 1% of net utility plant. No
maps depicting State Claims to property owned by the Company on the western
(Delaware River) side of New Jersey were published within one year period
mandated by the Constitutional Amendment. Nevertheless, the Company believes
it has obtained all necessary grants from the State for its improved
properties along the Delaware River.
Reference is made to the Consolidated 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 14 of AEI's Notes to Consolidated 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 the Consolidated
Financial Statements of the Company (Notes 3 and 11) 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
NONE
24
PART II
ITEM 5 MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
During all of 1997 and through February 1998 the Company's Common Stock was
listed on the New York Stock Exchange. All of ACE's Common Stock is owned by
the Company. At December 31, 1997, there were 47,500 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:
-------------
1997
First Quarter................................ $17.625 $16.375 $.385
Second Quarter............................... $17.000 $16.000 $.385
Third Quarter................................ $18.437 $16.312 $.385
Fourth Quarter............................... $21.562 $17.187 $.385
1996
First Quarter................................ $20.000 $16.625 $.385
Second Quarter............................... $18.750 $16.000 $.385
Third Quarter................................ $18.500 $17.000 $.385
Fourth Quarter............................... $18.875 $17.000 $.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. The ability of the Company to pay
dividends on its Common Stock was therefore governed by the ability of ACE to
pay dividends on its Common Stock. The rate and timing of future dividends of
Conectiv will depend upon the earnings and financial condition of Conectiv and
its subsidiaries, including ACE, and Delmarva Power & Light Company, and upon
other factors affecting dividend policy not presently determinable. It is
anticipated that Conectiv initially will pay an annual dividend of $1.54 per
share on its Common Stock and $3.20 per share annually on the Class A Common
Stock, subject to final determination by the Conectiv Board of Directors. The
Board's determination will be based upon Conectiv's results of operations,
financial condition, capital requirements and other relevant considerations.
ACE is subject to certain limitations on the payment of dividends. Whenever
full dividends on Preferred Stock have been paid for all past quarter-yearly
periods, ACE may pay dividends on Common Stock from funds legally available
for such purposes. 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 given effect
to such payment of 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.
25
ITEM 6SELECTED FINANCIAL DATA
Selected financial data for the Company and ACE for each of the last five
years is listed below.
ATLANTIC ENERGY, INC.
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
(THOUSANDS OF DOLLARS)
Operating
Revenue................. $1,102,360 $ 997,038* $ 958,054* $ 913,039* $ 865,675*
Net Income.............. $ 74,405 $ 58,767 $ 81,768 $ 76,113 $ 95,297
Basic and Diluted
Earnings per Average
Common Share........... $ 1.42 $ 1.12 $ 1.55 $ 1.41 $ 1.80
Total Assets (Year-
end)................... $2,723,884 $2,670,762 $2,617,888 $2,542,385 $2,487,508
Long Term Debt and
Redeemable Preferred
Securities (Year-
end)(b)................ $1,131,260 $1,051,945 $1,032,103 $ 940,788 $ 952,101
Capital Lease
Obligations (Year-
end)(b)................ $ 39,730 $ 39,914 $ 40,886 $ 42,030 $ 45,268
Common Dividends
Declared............... $ 1.54 $ 1.54 $ 1.54 $ 1.54 $ 1.535
ATLANTIC CITY ELECTRIC COMPANY
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
(THOUSANDS OF DOLLARS)
Operating Revenues...... $1,084,890 $ 989,647* $ 954,783* $ 913,226 $ 865,799
Net Income.............. $ 85,747 $ 75,017 $ 98,752 $ 93,174 $ 109,026
Income Available for
Common Shareholder(a).. $ 80,926 $ 65,113 $ 84,125 $ 76,458 $ 91,621
Total Assets (Year-
end)................... $2,436,755 $2,460,741 $2,459,104 $2,418,784 $2,363,584
Long Term Debt and
Redeemable Preferred
Securities (Year-
end)(b)................ $ 937,694 $ 926,370 $ 951,603 $ 924,788 $ 937,101
Capital Lease
Obligations (Year-
end)(b)................ $ 39,730 $ 39,914 $ 40,877 $ 42,030 $ 45,268
Common Dividends
Declared(a)............ $ 80,857 $ 82,163 $ 81,239 $ 83,482 $ 81,347
- --------
(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.
* Prior year amounts have been reclassified to conform to current year
reporting.
26
ITEM 7 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Atlantic Energy, Inc. (the Company, AEI or parent) merged with Delmarva
Power & Light Company (DP&L) into a new company named Conectiv, Inc.
(Conectiv) effective March 1, 1998. AEI is the parent of Atlantic City
Electric Company (ACE), Atlantic Energy Enterprises, Inc. (AEE) and Atlantic
Energy International, Inc. (AEII) which are wholly-owned subsidiaries. In
October 1997, the Company and DP&L entered into an agreement to form Conectiv
Solutions, LLC., a limited liability corporation to market and sell offerings
of energy, energy related services and other value-added services to large
customers.
FINANCIAL SUMMARY
Consolidated operating revenues for 1997, 1996 and 1995 were $1,102 million,
$997 million and $958 million, respectively. The increase in 1997 revenues
over 1996 is mostly due to increases in Wholesale Market Sales and Other
Services revenues. The increase in 1996 revenues over 1995 reflects an
increase in kilowatt hour sales and in annual Levelized Energy Clause (LEC)
revenues. These increases were offset in part by a $13.0 million revenue
credit recorded as a result of stipulation agreements. Prior years
consolidated operating revenues have been reclassified to conform to current
year presentation. (See Operating Revenues under Results of Operations).
Consolidated basic and diluted earnings per share for 1997 were $1.42 on net
income of $74.4 million compared to $1.12 on net income of $58.8 million in
1996 and $1.55 on net income of $81.8 million in 1995. The 1997 earnings
primarily reflect reduced Operations and Maintenance expenses associated with
the Salem outages which were offset by termination of employee benefit plan
costs in anticipation of the merger and losses from nonutility investments.
The 1996 earnings reflect charges resulting from provisions for rate refunds,
write-downs of nonutility property, losses from nonutility investments and
higher operations and maintenance expenses associated with the continuing
outage at the Salem Station.
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 is as
follows:
1997 1996 1995
---- ---- ----
Dividends Paid Per Share........................ $ 1.54 $ 1.54 $ 1.54
Book Value Per Share............................ $14.95 $15.00 $15.42
Annualized Dividend Yield....................... 7.3% 9.0 % 8.0%
Return on Average Common Equity................. 9.5% 7.4 % 9.9%
Total Return (Dividends paid plus change in
share price)................................... 32.7% (3.0)% 18.0%
Market to Book Value............................ 142% 114 % 125%
Price/Earnings Ratio............................ 15 15 12
Year End Closing Price -- NYSE.................. $21.19 $17.13 $19.25
MERGER
On August 12, 1996, the Boards of Directors of AEI and DP&L jointly
announced an agreement to merge the companies into a new company named
Conectiv. Conectiv, a newly formed Delaware corporation, became the parent of
AEI's subsidiaries and the parent of DP&L and its subsidiaries effective March
1, 1998. See discussion on approvals below.
DP&L is predominately a public utility engaged in electric and gas service.
DP&L provides retail and wholesale electric service to customers located in
about a 6,000 square mile territory located in Delaware, eastern shore
counties in Maryland and the eastern shore area of Virginia. DP&L provides gas
service to retail and transportation customers in an area consisting of about
275 square miles in Northern Delaware, including the City of Wilmington.
27
The merger is to be a tax-free, stock-for-stock transaction accounted for
under the purchase method of accounting with DP&L as the acquirer. Under the
terms of the agreement, DP&L shareholders will receive one share of Conectiv's
common stock for each share of DP&L common stock held. AEI shareholders will
receive 0.75 shares of Conectiv's common stock and 0.125 shares of Conectiv's
Class A common stock for each share of AEI common stock held.
On January 30, 1997, the merger was approved by the shareholders of both
companies. Approvals have since been obtained from the Federal Energy
Regulatory Commission (FERC), Delaware and Maryland Public Service
Commissions, the Virginia State Corporate Commission, the Pennsylvania Public
Utilities Commission, the Board of Public Utilities (BPU), and the Nuclear
Regulatory Commission (NRC). The last and final approval was received from the
Securities and Exchange Commission (SEC) on February 26, 1998. The merger
became effective March 1, 1998.
Under the terms of the BPU's approval of the merger, approximately 75
percent or $15.75 million of ACE's total average projected annual merger
savings will be returned to ACE's customers for an overall merger-related
reduction of 1.7 percent.
The total consideration to be paid to the Company's common stockholders,
measured by the average daily closing market price of the Company's common
stock for the three trading days immediately preceding and the three days
immediately following public announcement of the merger, is $921.0 million.
The consideration paid plus estimated acquisition costs and liabilities
assumed in connection with the merger are expected to exceed the net book
value of the Company's net assets by approximately $200.5 million, which will
be recorded as goodwill by Conectiv. The actual amount of goodwill recorded
will be based on the Company's net assets as of the merger date and,
accordingly, will vary from this estimate which is based on the Company's net
assets as of December 31, 1997. The goodwill will be amortized over 40 years.
On June 26, 1997, the Company and DP&L jointly announced an enhanced
retirement offer and separation program that will be utilized to achieve
workforce reductions as a result of the merger. The Company and DP&L initially
anticipated a combined loss of approximately 400 positions to accomplish the
merger-related rate reductions to customers. This initial level of reductions
will be achieved primarily through the DP&L early retirement and the Company's
enhanced retirement programs. Additional reductions are also anticipated to
better align staffing requirements to skill and work process needs. The
combined additional reductions could range between 250 to 350 positions. The
total cost to the Company for these programs, as well as the cost of executive
severance, employee relocation and facilities integration is estimated to
range from $38 million to $43 million. ACE is required to recognize these
costs through expense in accordance with GAAP. The actual cost to the Company
and ACE will depend on a number of factors related to the employee mix as well
as the actual number of employees who will be eligible for the enhanced
retirement or separation programs.
In the fourth quarter of 1997, the Company recorded an expense of $23.6
million as a result of terminating certain benefit programs of the Company in
anticipation of the merger. Termination of the plans resulted in charges of
$10.0 million for a supplemental executive retirement plan, $6.3 million due
to a pension plan curtailment, $3.8 million from the Equity Incentive Plan
(EIP) and $3.5 million from other benefit plans and executive contract
terminations. Refer to Note 5. in the Notes to the Consolidated Financial
Statements for discussion of the effects on the defined benefit pension plan
and the EIP.
ELECTRIC UTILITY INDUSTRY RESTRUCTURING AND STRANDED COSTS
In April 1997, the BPU issued its Final Report containing findings and
recommendations on the electric utility industry restructuring in New Jersey
to the Governor and the State Legislature for their consideration. The
recommendation for phase-in of retail choice to electric consumers calls for
choice to 10% of all customers beginning October 1, 1998 and to 100% by July
1, 2000. The Report required each electric utility in the state to file
complete restructuring plans, stranded cost filings and unbundled rate filings
by July 15, 1997. The Report
28
would allow utilities the opportunity to recover stranded costs on a case-by-
case basis, with no guarantee of 100 percent recovery of eligible stranded
costs.
ACE filed its response to the BPU on July 15, 1997. ACE's restructuring plan
met the BPU's recommendations for phase-in of retail electric access based on
a first-come, first-served basis, proposing choice to 10% of all customers
beginning October 1, 1998 and to 100% by July 1, 2000. Customers remaining
with ACE will be charged a market-based electricity price beginning October 1,
1998. The restructuring plan included a two-phased approach to future rate
reductions.
In an October 31, 1997 letter to the BPU, ACE added specificity to the
framework set out in the restructuring plan with regard to steps ACE
anticipates taking to meet the BPU's rate reduction and restructuring goals.
First, specific, definable cost reductions of approximately 4% after 1998 were
outlined. Further, ACE offered that an appropriate resolution of the merger
proceedings will allow ACE to reduce its rates, due to the merger,
approximately 1.25% upon consummation of the change in control. In addition,
ACE's current estimate showed that, through the use of securitized debt for
the full amount of stranded costs associated with its own generation assets, a
further rate decrease of up to 2% was possible based on appropriate
legislation and orders of the BPU with respect to securitization. Finally, ACE
estimates that the results of good-faith negotiations with the nonutility
generators could provide a reduction of up to an additional 1.75%. In summary,
ACE outlined a total rate reduction of 9% by the end of the transition. On
January 28, 1998, the BPU issued its Order establishing the procedural
schedule regarding the restructuring plan. Under that order, hearings on the
restructuring plan are to be completed by mid-May 1998. It is anticipated that
the BPU will issue its final order during the summer of 1998.
Under the stranded cost filing, ACE specified its total stranded cost
estimated to be approximately $1.3 billion, of which $911 million is
attributable to above-market nonutility generation (NUG) contracts. The
remaining amount, approximately $415 million, is related to wholly- and
jointly-owned generation investments. The stranded cost filing supports full
recovery of stranded costs, which ACE believes is necessary to move to a
competitive environment. On February 5, 1998, the Company filed rebuttal
testimony in the stranded cost filing. As part of the filing, the Company
updated its stranded cost estimates for the effects of tax law changes in the
State of New Jersey and to modify certain assumptions made in estimating the
stranded costs. The total stranded costs in the rebuttal filing are
approximately $1.2 billion with $812 million attributable to contracts and
$397 million related to wholly- and jointly-owned generation investments.
Determination of the stranded cost filing will be heard by the Office of
Administrative Law. The Administrative Law Judge is expected to render a
decision in May 1998. If ACE is required to recognize amounts as
unrecoverable, ACE may be required to write down asset values, and such
writedowns could be material.
ACE continues to meet the criteria set forth in SFAS 71 and has presented
these financial statements in accordance therewith. (See Note 1 --
Regulation -- ACE). The Financial Accounting Standards Board (FASB), through
the Emerging Issue Task Force (EITF), has recently set forth guidance intended
to clarify the accounting treatment of specific issues associated with the
restructuring of the electric utility industry through EITF Issue No. 97-4,
"Deregulation of the Pricing of Electricity -- Issues Related to the
Application of FASB Statements No. 71, Accounting for the Effects of Certain
Types of Regulation, and No. 101 Regulated Enterprises- Accounting for the
Discontinuation of application of FASB Statement No. 71" (EITF No. 97-4)". The
consensus reached in EITF No. 97-4 as to when an enterprise should stop
applying SFAS 71 to a separable portion of its business whose pricing is being
deregulated, is defined as "when deregulatory legislation or a rate order
(whichever is necessary to effect change in the jurisdiction) is issued that
contains sufficient detail for the enterprise to reasonably determine how the
transition plan will effect the separable portion of its business" (e.g.
generation).
Consensus was also reached "that the regulatory assets and regulatory
liabilities that originated in the separable portion of an enterprise to which
Statement 101 (SFAS 101, "Regulated Enterprises-Accounting for the
Discontinuance of Application of FASB Statement No. 71") is being applied
should be evaluated on the basis of where (that is, the portion of the
business in which) the regulated cash flows to realize and settle them,
29
respectively, will be derived." Additionally, the "source of the cash flow
approach adopted in the consensus should be used for recoveries of all costs
and settlements of all obligation (not just for regulatory assets and
regulatory liabilities that are recorded at the date Statement 101 is applied)
for which regulated cash flows are specifically provided in the deregulatory
legislation or rate order".
At this time ACE cannot predict, with certainty when it will stop applying
SFAS 71 for its generation business. ACE also cannot predict the impacts for
its generation business nor can it predict the impacts on its financial
condition as a result of applying SFAS 101. The outcome will be dependent upon
when a plan is approved and the level of recovery of stranded costs allowed by
the BPU. If assets require a write-down as a result of the application of SFAS
101, ACE may need to record an extraordinary noncash charge to operations that
could have a material impact on the financial position and results of
operations of ACE.
LIQUIDITY AND CAPITAL RESOURCES
ATLANTIC ENERGY, INC.
The Company's cash flows are dependent on the cash flows of its
subsidiaries, primarily ACE. Principal cash inflows of the Company were
dividends from ACE and proceeds from the Company's credit facility. Dividends
from ACE were $80.9 million, $82.2 million and $81.2 million for the years
1997, 1996 and 1995, respectively. Cash inflows from the Company's credit
facility amounted to $15.9 million, $3.1 million and $34.5 million during the
years 1997, 1996 and 1995, respectively.
The Company has a $75 million revolving credit and term loan facility. The
revolver is comprised of a 364-day senior revolving credit facility in the
amount of $35 million and a three-year senior revolving credit facility in the
amount of $40 million. Interest rates are based on senior debt ratings and on
the borrowing option selected by the Company. As of December 31, 1997 and
1996, AEI had $53.5 million and $37.6 million outstanding, respectively, from
this credit facility. This facility can be used to fund further reacquisitions
of Company Common Stock and other general corporate purposes up until the
effective date of the merger. At that time, a credit facility under Conectiv
will provide financing for general corporate purposes.
Principal cash outflows of the Company are dividends to shareholders and
disbursements to subsidiaries and affiliated companies in the form of capital
contributions, loans and advances. Dividends to shareholders amounted to $80.9
million in 1997 and $81.2 million in 1996 and 1995. Net Disbursements to
subsidiaries and affiliated companies amounted to $12.8 million, $1.2 million
and $.5 million for the years ended 1997, 1996 and 1995, respectively.
During 1995, the Company reacquired and cancelled 1,625,000 shares for a
total cost of $29.6 million with prices ranging from $17.625 to $18.875 per
share. At December 31, 1996 and 1995, the Company has reacquired and cancelled
a total of 1,846,700 shares of its common stock at a cost of $33.5 million.
The Company did not reacquire and cancel any shares under this program during
1996 and 1997. The Company's program to reacquire up to three million shares
of the it's common stock outstanding will expire with the merger.
Agreements between the Company and its subsidiaries provide for allocation
of tax liabilities and benefits generated by the respective subsidiaries.
Credit support agreements exist between the Company and ATE and AGI.
ATLANTIC CITY ELECTRIC COMPANY
ACE is a public utility primarily engaged in the generation, purchase,
transmission, distribution and sale of electric energy. ACE's service
territory encompasses approximately 2,700 square miles within the southern
one-third of New Jersey with the majority of customers being residential and
commercial. Cash construction expenditures for 1995-1997 amounted to $268.6
million and included expenditures for upgrades to existing transmission and
distribution facilities and compliance with provisions of the Clean Air Act
Amendments of
30
1990. ACE's current estimate of cash construction expenditures for 1998-2000
is $220.5 million. These estimated expenditures reflect necessary improvements
to generation, transmission and distribution facilities.
On an interim basis, ACE finances construction costs and other capital
requirements in excess of internally generated funds through the issuance of
unsecured short term debt, consisting of commercial paper and notes from
banks. As of December 31, 1997, ACE had authority to issue $150 million of
short term debt, comprised of $100 million of committed lines of credit and
$50 million on a when offered basis. At December 31, 1997, ACE had $77.9
million of unused short-term borrowing capacity. Short-term debt at December
31, 1997 decreased $9.3 million compared to December 31, 1996 and was used for
general corporate purposes. This decrease is net of $16.4 million reclassified
to noncurrent long-term debt due to the January 1998 issuance of medium term
notes discussed below.
Permanent financing by ACE is undertaken through the issuance of long term
debt and preferred stock, and from capital contributions by AEI. ACE's nuclear
fuel requirements associated with its jointly-owned units have been financed
through arrangements with a third party.
A summary of the issue and sale of ACE's long term debt and preferred
securities for 1995-1997 is as follows:
1997 1996 1995
(MILLIONS) ---- ---- ----
Medium Term Notes......................................... $65 -- $105
Pollution Control Bonds................................... 22.6 -- --
Cumulative Quarterly Income Preferred Securities.......... -- $70 --
The proceeds from these financings were used to refund higher cost debt,
preferred stock, and for construction purposes. ACE may issue up to $150
million in long term debt to be used for construction, refundings and
repayment of short term debt up through 2000. The 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, 1997, ACE
estimates additional funding capacities of $264.3 million of First Mortgage
Bonds, or $489 million of preferred stock, or $110.8 million of unsecured
debt. These amounts are not necessarily additive.
On July 30, 1997, ACE issued $22.6 million aggregate principal amount of
variable rate, tax-exempt pollution control bonds in two separate series:
$18.2 million Pollution Control Revenue Refunding Bonds, 1997 Series A due
April 15, 2014 (Series A) and $4.4 million Pollution Control Revenue Refunding
Bonds, 1997 Series B due July 15, 2017 (Series B). The Series A and the Series
B bonds paid an initial weekly rate of 3.4% and 3.5%, respectively. Each
subsequent rate is determined by the remarketing agent. The proceeds from the
sale of the Series A and Series B bonds were applied to the September 2, 1997
redemption of $18.2 million aggregate principal amount of 7 3/8% Pollution
Control Revenue Bonds of 1984, Series A and $4.4 million aggregate principal
amount of 8 1/4% Pollution Control Revenue Bonds of 1987, Series B. Aggregate
premiums paid for the September 2, 1997, redemption were $546,000 and $88,000,
respectively.
During 1997, ACE issued and sold $65 million aggregate principal amount of
unsecured Medium Term Notes. Primarily, the notes were sold to cover the
December 1, 1997, redemption of $20 million principal amount of 7.5% First
Mortgage Bonds due April 1, 2002 and $29.976 million principal amount of 7.75%
First Mortgage Bonds due June 1, 2003. Aggregate premiums paid for the
redemption of these bonds were $240,000 and $440,647, respectively.
On January 12, 1998, ACE issued $85 million of Secured Medium Term Notes,
Series D maturing at January 2003 and January 2006. The Notes paid fixed
interest rates of 6.0%, 6.2% and 6.2%. The net proceeds to be received by the
Company from the issuance and sale of the Medium Term Notes will be applied to
the repayment of outstanding short-term and long-term indebtedness, including
the redemption of certain series of First Mortgage Bonds, Preferred Stock and
unsecured short-term debt due in 1998.
31
Listed below is a schedule of redemptions of Preferred Stock and long term
debt redeemed, acquired and retired or matured for the period 1995-1997.
SHARES
-------------------------- REDEMPTION
1997 1996 1995 PRICE
---- ---- ---- ----------
Preferred Stock:
(Series)
$8.20.............................. 200,000 200,000 $100.00
$8.53.............................. 120,000 101.00
7.52%............................. 100,000 101.88
$8.25.............................. 50,000 104.45
$7.80.............................. 460,500 111.00
$8.53.............................. 240,000 100.00
$8.25.............................. 5,000 100.00
Aggregate Amount (000)............... $20,000 $98,876* $24,500
- --------
* includes commissions and premiums
PRINCIPAL REDEMPTION
DATE SERIES AMOUNT PRICE %
---- ------ --------- ----------
(000)
Long Term Debt:
September 1997...................... 7 3/8% due 2014 $18,200 103.00
September 1997...................... 8 1/4% due 2017 4,400 102.00
December 1997....................... 7 1/2% due 2002 20,000 101.20
December 1997....................... 7 3/4% due 2003 29,976 101.47
February 1996....................... 5 1/8% due 1996 9,980 100.00
February 1996....................... 5 1/4% due 1996 2,267 100.00
October 1995........................ 9 1/4% due 2019 53,857 105.15
October 1995........................ 10 1/2% due 2014 850 101.00
On May 1, 1997, ACE satisfied the sinking fund requirements of $100,000 for
its 7 1/4% Debentures and on December 1, 1997 satisfied the sinking fund
requirement of $75,000 of its 6 3/8% Pollution Control Series due December 1,
2006. Scheduled maturities and sinking fund requirements for long term debt
and preferred stock aggregate $199.3 million for 1998-2002.
On April 1, 1997 ACE and other New Jersey utilities were required to pay
excise taxes to the State of New Jersey. ACE paid $91.1 million funded through
the issuance of short term debt with repayment of such debt occurring during
the second and third quarters.
ATLANTIC ENERGY ENTERPRISES, INC.
AEE is a holding company which is responsible for the management of the
investments in the nonutility companies consisting of: Atlantic Generation,
Inc. (AGI); Atlantic Southern Properties, Inc. (ASP); ATE Investment, Inc.
(ATE); Atlantic Thermal Systems, Inc. (ATS); CoastalComm, Inc. (CCI) and
Atlantic Energy Technology, Inc. (AET). Also, AEE has a 50% equity interest in
Enerval, LLC, (Enerval) a company which provides energy management services,
including natural gas supply, transportation and marketing.
As a service to Enerval, the other 50% owner enters into futures contracts
on Enerval's behalf. As of December 31, 1997, this owner entered into natural
gas futures contracts on behalf of Enerval for 9.3 million DTH at a price
range of $1.90 to $3.20, through March 2000 in the notional amount of $21.2
million. The original contract terms range from one month to two years.
Enerval's futures contracts hedge $21.7 million in anticipated natural gas
sales. The counterparties to the futures contracts are the New York Mercantile
Exchange
32
and major over the counter market traders. The Company believes the risk of
nonperformance by these counterparties is not significant. If the contracts
had been terminated at December 31, 1997, $0.6 million would have been payable
by Enerval for the natural gas price fluctuations.
AEE obtains funds for its investments and operating needs through advances
from AEI and notes payable to ATE. Funds for AEE capital investments will be
provided through issuance of ATE long term debt and equity investments by AEI
up to the effective merger date.
ATLANTIC GENERATION, INC.
AGI is engaged in the development, acquisition, ownership and operation of
cogeneration power projects. AGI's activities through its subsidiaries are
primarily represented by partnership interests in cogeneration facilities
located in New Jersey. At December 31, 1997, total investments in these
partnerships amounted to $18.7 million.
ATLANTIC SOUTHERN PROPERTIES, INC.
ASP owns and manages two commercial office buildings and a warehouse
facility located in Atlantic County, New Jersey with a net book value of $9.2
million at December 31, 1997. In 1996 a write-down of the carrying value of a
facility of $0.8 million, net of tax was recorded to reflect the recognition
of the diminished value due to the excess vacancy and a decline in the local
commercial real estate market. This investment has been funded by capital
contributions from AEI and borrowings under a loan agreement with ATE.
ATE INVESTMENT, INC.
ATE provides financing to affiliates and manages a portfolio of investments
in leveraged leases. ATE has invested $80.4 million in leveraged leases of
three commercial aircraft and two containerships. ATE along with an
unaffiliated company joined together to create an equity limited partnership,
EnerTech Capital Partners, L.P., (Enertech). Enertech invests in and supports
a variety of energy related technology growth companies. At December 31, 1997
ATE had invested $10.2 million in this partnership. Enertech accounts for its
investment under the investment method of accounting. ATE obtained funds for
its business activities and loans to affiliates through capital contributions
from AEI and external borrowings. These borrowings include $15 million
principal amount of 7.44% Senior Notes due 1999 and a revolving credit and
term loan facility of up to $25 million. At December 31, 1997, $5.0 million
was outstanding under this facility. ATE's cash flows are provided from lease
rental receipts and realization of tax benefits generated by the leveraged
leases. ATE has notes receivable, including interest, outstanding with ASP
which totaled $10.3 million at December 31, 1997. ATE has established credit
arrangements with AEE, of which $8.3 million was a receivable, including
interest, at December 31, 1997.
ATLANTIC THERMAL SYSTEMS, INC.
ATS and its wholly-owned subsidiaries are engaged in the development and
operation of thermal heating and cooling systems. ATS plans to make $125
million in capital expenditures related to district heating and cooling
systems to serve the business and casino district in Atlantic City, New Jersey
and has invested $84.8 million as of December 31, 1997. Construction for the
Midtown Energy Center is complete and has been in a testing phase since
October 1997. Commercial operation began January 1, 1998. ATS has obtained
funds for its project development through a revolving credit agreement and
term loan. ATS's $100 million credit facility was amended and restated to $143
million in October 1997. Up to $50 million of the available credit commitment
can be used to establish letters of credit. As of December 31, 1997, $89.1
million was outstanding under this facility. Additional funding for the
project came from $12.5 million from the proceeds of special, limited
obligation bonds issued by the New Jersey Economic Development Authority
(NJEDA). Proceeds from the sale were placed in escrow. The proceeds may be
released to the ATS partnership and used to pay certain "qualified costs"
subject to satisfaction of certain conditions. In November 1997, ATS satisfied
the escrow release conditions and remarketed, through underwriters, $12.5
million principal amount, Series 1995 Thermal Energy
33
Facilities Revenue Bonds due December 1, 2009 at variable rates of interest.
Since issuance, the interest rates to the ATS partnership have ranged from
2.5% to 4.1%. In addition, the NJEDA issued an additional $18.5 million in
limited obligation bonds which were sold, through underwriters, as Series 1997
Thermal Energy Facilities Revenue Bonds due December 1, 2031 at variable rates
which have ranged from 2.5% to 4.1%. ATS applied $20.0 million of bond
proceeds to reimburse it for certain qualifying costs incurred during
construction of the Midtown Energy Center in Atlantic City, New Jersey.
Proceeds of $11.0 million remained in escrow at December 31, 1997 pending
verification of compliance with NJEDA qualifications.
ATS has agreements with six casinos in Atlantic City, New Jersey to operate
their heating and cooling systems. As part of these agreements, ATS has paid
$27.5 million in license fees for the right to operate and service such
systems for a period of 20 years. ATS recorded $1.2 million in expense for
these license fees which are recorded on the Consolidated Balance Sheet as
License Fees and are being amortized to expense over the life of the
contracts.
RESULTS OF OPERATIONS
Operating results of AEI as a consolidated group are dependent upon the
performance of its subsidiaries, primarily ACE.
OPERATING REVENUES
Operating revenues increased 10.6% and 4.1% in 1997 and 1996, respectively.
Electric revenues increased 8.1% and 3.0% in 1997 and 1996, respectively.
Components of the overall operating revenue changes are shown as follows:
1997 1996
---- ----
(MILLIONS)
Base Revenues............................................. $ 1.0 $ (8.9)
Refund Credits............................................ -- (13.0)
Levelized Energy Clause................................... 15.3 29.3
Kilowatt-hour Sales....................................... (4.1) 32.2
Unbilled Revenues......................................... 11.8 (17.6)
Wholesale Market Sales.................................... 70.2 1.9
Sales for Resale.......................................... (16.9) 6.0
Other Services............................................ 25.4 10.0
Other..................................................... 2.6 (.9)
------ ------
Total..................................................... $105.3 $ 39.0
====== ======
The increase in Base Revenues for the current year reflects the $13.0
million refund to customers recorded in 1996 as the result of a stipulation
agreement which was offset by the effects of ACE's BPU approved Off-Tariff
Rate Agreements (OTRAs). OTRAs are special reduced rates offered by ACE to at-
risk customers which aggregated $10.5 million and $3.5 million for the years
ended December 31, 1997 and 1996, respectively. At-risk customers are
customers who may choose to leave ACE's energy system because they have
alternative energy sources available. The Refund Credits are the result of the
October 22, 1996 stipulations for the $13.0 million settlement concerning the
outages of the Salem Units and the alleged overrecovery of capacity costs from
nonutility generation facilities. See Note 3 of the consolidated financial
statements for further details regarding the stipulations.
LEC revenues increased in 1997 due to a rate increase of $27.6 million in
July 1996. 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 2.4% and
0.9% in revenues per kilowatt-hour in 1997 and 1996, respectively. The changes
in Unbilled Revenues are a result of the amount
34
of kilowatt-hours consumed by, but not yet billed to, ultimate customers at
the end of the respective periods, which are affected by weather and economic
conditions, and the corresponding price per kilowatt-hour.
Wholesale Market Sales represent bulk power sales, which are not subject to
price regulation. ACE began making such sales in July 1996. Wholesale Market
Sales and the related expenses were previously included in Other-Net, within
Other Income on the Consolidated Statement of Income. (See Note 1 --
Reclassification). The increase in 1997 sales represent an increase in bulk
power sales due to a full year's operation as well as a result of ACE's
strategy and development of a business opportunity.
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 decrease in the
1997 Sales for Resale is primarily due to a change in ACE's energy mix
strategy, using Wholesale Market Sales to service previous Sales for Resale
customers.
Other Services Revenues represent non-regulated energy services of ACE and
revenues of AEE which were previously included in Other-Net, within Other
Income on the Consolidated Statement of Income. Other Services Revenues
increased significantly primarily reflecting ATS's casino heating and cooling
service contracts and the growth of ACE's energy services programs.
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:
1997 1996
---- ----
AVG AVG# AVG AVG #
CUSTOMER CLASS SALES USE OF CUST SALES USE OF CUST
-------------- ----- --- ------- ----- --- -------
Residential....................... (3.7)% (4.6)% 1.0% 3.2% 2.4% 0.8%
Commercial........................ 1.3 (0.5) 1.8 3.0 2.0 1.0
Industrial........................ 3.2 2.6 0.6 7.1 5.5 1.5
Total............................. (0.6) (1.7) 1.1 3.6 2.8 0.8
The 1997 decrease in actual billed sales was due to unfavorable weather in
1997 and a lesser number of billing days in 1997 compared to 1996. The
decrease in 1997 Residential sales was a result of above normal temperatures
in the first quarter of 1997 and cooler than normal weather in late August and
early September 1997. Casino expansions and construction around Atlantic City,
New Jersey were significant contributors to commercial sales growth in 1997.
The increased 1997 Industrial sales were primarily due to the impact of two
customers that had previously been supplied by an independent power producer.
In 1996, the growth rate of actual billed sales increased significantly from
1995 due to an increase in the number of billing days and more favorable
weather conditions. Sales growth was offset by cooler than normal summer
weather conditions in 1996. Casino expansions and construction around Atlantic
City, New Jersey were significant contributors to commercial sales growth in
1996. The increase in 1996 Industrial sales was primarily due to the impact of
two customers, which began service in late 1996, that had previously been
supplied by an independent power producer.
COSTS AND EXPENSES
Total Operating Expenses for the Company increased 8.9% and 9.1% in 1997 and
1996, respectively. Operating expenses for ACE increased 8.5% in both 1997 and
1996. Included in these expenses are the costs of energy, purchased capacity,
operations, maintenance, depreciation, state excise taxes and taxes other than
income tax.
35
Operating Expenses
Energy expense reflects costs incurred for energy needed to meet load
requirements, various energy supply sources used, wholesale market purchases
and operation of the LEC. 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 Power Pool. The cost of energy, except for the
nonregulated purchases, is recovered from customers primarily through the
operation of the LEC. Generally, earnings are not affected by recoverable
energy costs because these costs are adjusted to match the associated LEC
revenues. However, ACE had voluntarily foregone recovery of certain amounts of
otherwise recoverable fuel costs through its Southern New Jersey Economic
Initiative (SNJEI), thereby, reducing earnings through May 1996, as indicated
below. Otherwise, in any period, the actual amount of LEC revenue recovered
from customers may be greater or less than the actual amount of recoverable
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 from 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 $27.4 million and by $33.5 million at December 31,
1997 and 1996, respectively.
Energy expense increased 30.3% in 1997 primarily due to expenses associated
with the first full year of activity in Wholesale Market Sales. Energy expense
increased 17.4% in 1996 primarily due to the changes in the LEC effective July
17, 1996, permitting ACE to begin recovering over $35.3 million in previously
deferred energy costs. Production related energy costs for 1996 increased 5.3%
due to increased sales. As a result of implementing the SNJEI, after tax net
income has been reduced by $2.7 million for 1996.
Purchased Capacity expense reflects entitlement to generating capacity owned
by others. Purchased Capacity expense increased 2.7% in 1996. The increase
reflects additional contract capacity supplied by nonutility power producers.
Operations expenses decreased 3.4% in 1997 and increased 9.9% in 1996. The
decrease in 1997 reflects reductions in operations expense relating to the
Salem outages. The 1996 increase reflects additional costs associated with
Salem Station restart activities offset in part by a credit for the estimated
1995 Nuclear Performance Penalty.
Maintenance expense decreased 26.2% in 1997. This decrease reflects
reductions in maintenance expenses relating to the Salem outage. Maintenance
expense increased 28.8% in 1996 as a result of additional cost associated with
the Salem Station restart activities, and increased maintenance initiatives.
Termination of Employee Benefits represents amounts recorded in December
1997 for the cost to terminate various pension and compensation plans in
anticipation of the merger.
Other-Net within Other Income increased 20.6% in 1997, this was primarily
due to a gain on the sale of property. Other-net decreased 29.5% in 1996 due
to the net after-tax impacts of the write-down of the carrying value of ASP's
commercial property of $1.2 million, the contingency loss for the sale of
Binghamton Cogeneration facility of $2.5 million. Also included is a loss of
$1.6 million from AEE's investment in Enerval due to a combination of unhedged
gas sales agreements and higher spot market prices for gas.
Interest expense increased 2.2% in 1997 and 4.6% in 1996 due primarily to
increased short-term debt borrowings.
Preferred Securities Dividend Requirements decreased 6.5% and 22.5% in 1997
and 1996, respectively, as a result of mandatory and optional redemptions.
36
Income Taxes
Federal Income Taxes increased 33.1% in 1997 and decreased 28.5% in 1996 as
a result of the level of taxable income during those periods.
SALEM NUCLEAR GENERATING STATION
ACE is an owner of 7.41% of Salem Units 1 and 2, which are operated by
Public Service Electric and Gas Company (PS). The Salem units represent 164
MWs of ACE's total installed capacity of 2,415.7 MWs. Salem Unit 1 has been
out of service since May 16, 1995. Salem Unit 2, out of service since June 7,
1995 returned to service on August 30, 1997 and reached 100% power on
September 23, 1997.
PS has advised ACE that the installation of Salem Unit 1 steam generators
has been completed. The cost of purchasing and installing the steam
generators, as well as the disposal of the old generators is $186 million, of
which ACE's share is $13.8 million. The unit is currently expected to return
to service during the second quarter of 1998. Restart of Salem Unit 1 is also
subject to NRC approval.
The Salem Station outages has caused ACE to incur replacement power costs of
approximately $700 thousand per month per unit. As previously discussed, ACE's
replacement power costs for the current and recent outage, up to the agreed-
upon return-to-service date of June 30, 1997 for Salem Unit 1 and December 31,
1996 for Salem Unit 2, will be recoverable in rates in ACE's 1997 LEC
proceeding. Replacement power costs incurred after the agreed-upon return-to-
service date for the Salem Station will not be recoverable in rates. ACE has
incurred $10.2 million in non-recoverable replacement power costs to date
related to Salem.
ACE entered into an agreement with PS for the purpose of limiting ACE's
exposure to Salem's 1997 operation and maintenance (O&M) expenses. Pursuant to
the terms of the agreement, ACE was obligated to pay to PS $10 million of O&M
expense, as a fixed charge payable in twelve equal installments beginning
February 1, 1997. ACE's obligation for any contributions, above the $10
million, to Salem 1997 O&M expenses up to ACE's estimated share of $21.8
million, is based on performance and directly related to the timely return and
operation of the units. As a result of this Agreement, ACE agreed to dismiss
the complaint filed in the Superior Court of New Jersey in March 1996 alleging
negligence and breach of contract.
On February 27, 1996, the Salem co-owners filed a Complaint in United States
District Court for the District of New Jersey against Westinghouse Electric
Corporation, the designer and manufacturer of the Salem steam generators,
under Federal and state statutes alleging fraud, negligent misrepresentation
and breach of contract. The litigation is continuing in accordance with the
schedule established by the court.
OTHER
The Energy Policy Act of 1992 permits the Federal government to assess
investor-owned electric utilities that have ownership interests in nuclear
generating facilities for the decontamination and decommissioning of Federally
operated nuclear enrichment facilities. Based on its ownership in five nuclear
generating units, ACE has a liability of $4.6 million and $5.3 million at
December 31, 1997 and 1996, respectively, for its obligation to be paid over
the next 12 years. ACE has an associated regulatory asset of $5.0 million and
$5.7 million at December 31, 1997 and 1996, 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.
ACE is subject to a performance standard for its five jointly-owned nuclear
units. This standard is used by the BPU in determining recovery of replacement
energy costs when output from the nuclear units is reduced or not available.
Underperformance results in penalties which are not permitted to be recovered
from customers and are charged against income. According to a December 1996
stipulation agreement, the performance of Salem Units 1 and 2 shall not be
included in the calculation of a nuclear performance penalty for the period
each unit was taken out of service up to each unit's respective return-to-
service date. The parties to the stipulation agreed
37
that for the years 1995 and 1996, there will be no penalty under the nuclear
performance standard. Additionally, ACE will not incur a nuclear performance
penalty for 1997.
YEAR 2000 DISCLOSURE
The Company's Information Technology Department (IT), through a Conectiv
project team, has developed a strategy to address and correct the year 2000
problem (Y2K). An inventory of the Company's computer applications, hardware
and system software and infrastructure has been completed. An initial
assessment of these systems has been made as they relate to the Y2K. The
project team's goal is to resolve Y2K related problems associated with core
systems by the close of 1998. The Company has also contacted major vendors to
review remediation of their Y2K issues. The Company estimates that
approximately $3 million is necessary for IT to complete the scope of their
responsibilities. The Company has not estimated the expected cost to complete
this project in all other areas. The Company believes that it is taking the
necessary steps to minimize the risk of an interruption of service to its
operations and customers.
OUTLOOK
With the merger of AEI into a new company known as Conectiv the Company is
focusing on the objectives of Conectiv which will be carried out by three
strategic business units -- Regulated Delivery, Energy Supply and Retail
Businesses. The business units will provide services to the competitive
regional marketplace aligning Conectiv's organization with the changing needs
of its customers and markets. Regulated Delivery will focus on providing high
value utility delivery service to customers. Energy Supply will maximize the
value of generation, while managing the transition to a competitive generation
market. The goal of the Retail businesses is to become a regional full-service
company providing value-added products and services for the retail energy
consumer which create customer loyalty and satisfaction.
The utility business will continue to be the primary factor influencing
Conectiv's overall financial performance. For ACE, legislative changes in the
regulated electric utility industry in New Jersey will have a significant
impact on ACE's economic viability and ability to compete in the energy
marketplace. ACE's restructuring filing, which proposes customer choice
starting October 1998, outlines a plan that could ultimately reduce rates by
9%. Achievement of such goals will depend upon the success of ACE's commitment
to good-faith negotiations with independent power producers, as well as
legislation to support securitization for the full amount of its stranded
costs.
ACE's restructuring filing supports full recovery of stranded costs, which
it believes is also necessary to move to a competitive environment. If ACE is
required to recognize amounts as unrecoverable, ACE may be required to write
down asset values, and such writedowns could be material.
ACE's generation business will be faced with the effects of competition in
the very near term. ACE's retail prices are expected to be critical success
factors in a competitive marketplace. At this time ACE cannot predict, with
certainty when it will stop applying SFAS 71 for its generation business and
cannot predict the impacts for its generation business or predict the impacts
on its financial condition as a result of applying SFAS 101.
ACE's utility business will continue to be affected by regional economic
trends and social initiatives, as well as the impacts of abnormal weather and
inflation. Such regional economic trends are favorable and include the growth
of Atlantic City and the gaming industry. Ongoing requirements for service
reliability, and compliance with existing and new environmental regulations,
will continue to cause additional capital investments to be made by ACE. ACE's
planned construction budget is $324.8 million for the five year period
beginning in 1998. ACE's ability to generate cash flows or access the capital
markets may be affected by competitive pressures on revenues and income.
As of January 1, 1998 ATS's Midtown Energy Center began operations servicing
casino-hotels within the city of Atlantic City. These operations are for phase
1 of a 5 phase plan to service customers in the "Midtown"
38
section of the city. As of January 1, 1998, 78% of the capitalized costs for
the Midtown Energy Center are in operation. ATS arose out of a business
opportunity resulting from the combination of casino growth and expansion and
state environmental and regulatory changes. ATS has undertaken additional
projects and continues to explore opportunities locally and throughout the
United States. All of AEE's businesses will be blended into Conectiv's
strategic plans and current businesses and investments will be evaluated to
support corporate objectives.
The merger is part of a wider trend in the utility industry toward
consolidation and strategic partnerships in order to create larger, stronger
companies for the onset of competition. The opportunities which will be
derived from increased financial strength, improved management, efficiencies
of operations and better utilization and coordination of existing and future
facilities will provide Conectiv the strategic and operational opportunities
to better meet the coming 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
both market circumstances and the frequency, timing and results of rate case
decisions.
OTHER
The Private Securities Litigation Reform Act of 1995 (the Act) provides a
new "safe harbor" for forward-looking statements to encourage such disclosures
without the threat of litigation providing those statements are identified as
forward-looking and are accompanied by meaningful, cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Forward-looking statements
have been and will be made in written documents and oral presentation of AEI
and its subsidiaries. Such statements are based on managements beliefs as well
as assumptions made by and information currently available to management. When
used in AEI and subsidiary documents or oral presentation, the words
"anticipate", "estimate", "expect", "objective" and similar expressions are
intended to identify such forward-looking statements. In addition to any
assumptions and other factors referred to specifically in connection with such
forward-looking statements, factors that could cause actual results to differ
materially from those contemplated in any forward-looking statements include,
among others, the following: deregulation, and the unbundling of energy
supplies and services; an increasingly competitive energy marketplace; sales
retention and growth potential in a mature service territory and a need to
contain costs; ability to obtain adequate and timely rate relief, cost
recovery, including the potential impact of stranded costs, and other
necessary regulatory approvals; federal and state regulatory actions; costs of
construction; operating restrictions, increased cost and construction delays
attributable to environmental regulations; controversies regarding electric
and magnetic fields; nuclear decommissioning and the availability of
reprocessing and storage facilities for spent nuclear fuel; licensing and
regulatory approval necessary for nuclear and other operating station; and
credit market concerns with these issues. AEI and its subsidiaries undertake
no obligation to publicly update or revise any forward-looking statements,
whether as a result of new information, future events or otherwise. The
foregoing review of factors pursuant to the Act should not be construed as
exhaustive or as any admission regarding the adequacy of disclosures made by
AEI and its subsidiaries prior to the effective date of the Act.
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY
The information required by this item is incorporated herein by reference
from the following portions of AEI's Management's Discussion and Analysis of
Financial Condition and Results of Operations, insofar as they relate to ACE
and its subsidiary: Financial Summary, Liquidity and Capital Resources --
Atlantic City Electric Company, Results of Operations, Salem Nuclear
Generating Station, Competition, Outlook, Inflation and Other.
39
ITEM 8FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF MANAGEMENT-ATLANTIC ENERGY, INC.
The management of Atlantic Energy, Inc. and its subsidiaries (the Company)
is responsible for the preparation of the consolidated financial statements
presented in this Annual Report. The financial statements have been prepared
in conformity with generally accepted accounting principles. In preparing the
consolidated financial statements, management made informed judgments and
estimates, as necessary, relating to events and transactions reported.
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, 1997, 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 consolidated 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, 1997 represented
significant deficiencies in the design or operation of the Company's internal
control structure.
/s/ J. L. Jacobs
J. L. Jacobs
Chairman and Chief Executive
Officer
/s/ M. J. Barron
M. J. Barron
Senior Vice President and Chief
Financial Officer
February 2, 1998
40
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: Matthew Holden, Jr.,
Kathleen MacDonnell, Bernard J. Morgan and Harold J. Raveche. The Committee
held four meetings during 1997.
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 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, 1997 as a result of any communications conducted.
/s/ Matthew Holden, Jr.
Matthew Holden, Jr.
Chairman, Audit Committee
February 2, 1998
41
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, 1997 and 1996 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, 1997.
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 audits 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
subsidiaries at December 31, 1997 and 1996 and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1997 in conformity with generally accepted accounting principles.
/s/ Deloitte & Touche LLP
- -----------------------
Deloitte & Touche LLP
February 2, 1998 (March 1, 1998 as to Note 4)
Parsippany, New Jersey
42
ATLANTIC ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(DOLLARS, IN THOUSANDS)
ASSETS
DECEMBER 31,
------------
1997 1996
---- ----
Electric Utility Plant
In Service:
Production............................................. $1,242,049 $1,212,380
Transmission........................................... 383,577 373,358
Distribution........................................... 763,915 731,272
General................................................ 195,745 191,210
---------- ----------
Total In Service........................................ 2,585,286 2,508,220
Less Accumulated Depreciation........................... 934,235 871,531
---------- ----------
Utility Plant in Service-Net............................ 1,651,051 1,636,689
Construction Work in Progress........................... 95,120 117,188
Land Held for Future Use................................ 5,604 5,604
Leased Property-Net..................................... 39,730 39,914
---------- ----------
1,791,505 1,799,395
---------- ----------
Investments and Nonutility Property
Investment in Leveraged Leases......................... 80,448 79,687
Nuclear Decommissioning Trust Fund..................... 81,650 71,120
Nonutility Property and Equipment-Net.................. 105,356 46,147
Other Investments and Funds............................ 53,859 53,550
---------- ----------
321,313 250,504
---------- ----------
Current Assets
Cash and Temporary Investments.......................... 17,224 15,278
Accounts Receivable:
Utility Service........................................ 64,511 64,432
Miscellaneous.......................................... 42,034 32,547
Allowance for Doubtful Accounts........................ (3,500) (3,500)
Unbilled Revenues....................................... 36,915 33,315
Fuel (at average cost).................................. 29,242 29,682
Materials and Supplies (at average cost)................ 20,893 23,815
Working Funds........................................... 15,126 15,517
Deferred Energy Costs................................... 27,424 33,529
Prepaid Excise Tax...................................... 3,804 7,125
Other................................................... 14,349 11,354
---------- ----------
268,022 263,094
---------- ----------
Deferred Debits
Unrecovered Purchased Power Costs....................... 66,264 83,400
Recoverable Future Federal Income Taxes................. 85,858 85,858
Unrecovered State Excise Taxes.......................... 45,154 54,714
Unamortized Debt Costs.................................. 44,947 44,423
Deferred Other Post Employee Benefit Costs.............. 37,476 32,609
Other Regulatory Assets................................. 24,637 26,966
License Fees............................................ 26,081 17,733
Other................................................... 12,627 12,066
---------- ----------
343,044 357,769
---------- ----------
Total Assets............................................ $2,723,884 $2,670,762
========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
43
ATLANTIC ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(DOLLARS, IN THOUSANDS)
LIABILITIES AND CAPITALIZATION
DECEMBER 31,
------------
1997 1996
---- ----
Capitalization
Common Shareholders' Equity
Common Stock, no par value; 75,000,000 shares
authorized; issued and outstanding:
1997 -- 52,504,479; 1996 -- 52,502,479.................. $ 563,460 $ 562,746
Retained Earnings....................................... 221,623 227,630
Unearned Compensation................................... -- (2,982)
---------- ----------
Total Common Shareholders' Equity....................... 785,083 787,394
Preferred Securities of ACE:
Not Subject to Mandatory Redemption.................... 30,000 30,000
Subject to Mandatory Redemption........................ 33,950 43,950
ACE-Obligated Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of ACE........................ 70,000 70,000
Long Term Debt.......................................... 879,744 829,745
---------- ----------
1,798,777 1,761,089
---------- ----------
Current Liabilities
Preferred Stock Redemption Requirement.................. -- 10,000
Capital Lease Obligation-Current Portion................ 653 702
Long Term Debt-Current Portion.......................... 147,566 98,250
Short Term Debt......................................... 55,675 64,950
Accounts Payable........................................ 65,369 66,508
Taxes Accrued........................................... 6,049 7,504
Interest Accrued........................................ 20,116 20,241
Dividends Declared...................................... 21,215 21,701
Deferred Income Taxes................................... 1,888 3,190
Provision for Rate Refunds.............................. -- 13,000
Other................................................... 23,995 20,853
---------- ----------
342,526 326,899
---------- ----------
Deferred Credits and Other Liabilities
Deferred Income Taxes................................... 439,267 434,108
Deferred Investment Tax Credits......................... 44,043 46,577
Capital Lease Obligations............................... 39,077 39,212
Accrued Other Post Retirement Employee Benefit Costs.... 37,476 32,609
Other................................................... 22,718 30,268
---------- ----------
582,581 582,774
---------- ----------
Commitments and Contingencies (Note 11)
Total Liabilities and Capitalization.................... $2,723,884 $2,670,762
========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
44
ATLANTIC ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(DOLLARS, IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
---- ---- ----
Operating Revenues
Electric................................ $ 1,061,986 $ 982,123 $ 953,137
Other Services.......................... 40,374 14,915 4,917
------------ ---------- ----------
1,102,360 997,038 958,054
------------ ---------- ----------
Operating Expenses
Energy.................................. 293,457 225,185 191,766
Purchased Capacity...................... 197,386 195,699 190,570
Operations.............................. 170,340 176,326 160,503
Maintenance............................. 32,858 44,534 34,564
Termination of Employee Benefit Plans... 23,559 -- --
Depreciation and Amortization........... 83,950 81,595 79,232
State Excise Taxes...................... 103,991 104,815 102,811
Taxes Other Than Income................. 7,616 10,207 8,977
------------ ---------- ----------
913,157 838,361 768,423
------------ ---------- ----------
Operating Income........................ 189,203 158,677 189,631
------------ ---------- ----------
Other Income and Expense
Allowance for Equity Funds Used During
Construction........................... 815 879 817
Other-Net............................... 14,598 12,100 17,155
------------ ---------- ----------
15,413 12,979 17,972
------------ ---------- ----------
Interest Charges
Interest Expense........................ 70,619 69,116 66,049
Allowance for Borrowed Funds Used During
Construction........................... (1,003) (976) (1,678)
------------ ---------- ----------
69,616 68,140 64,371
------------ ---------- ----------
Less Preferred Securities Dividends
Requirements of Subsidiary............. 10,596 11,332 14,627
------------ ---------- ----------
Income Before Income Taxes.............. 124,404 92,184 128,605
------------ ---------- ----------
Income Taxes............................ 49,999 33,417 46,837
------------ ---------- ----------
Net Income.............................. $ 74,405 $ 58,767 $ 81,768
============ ========== ==========
Common Stock
Average Basic Shares Outstanding (000).. 52,281 52,299 52,595
Average Diluted Shares Outstanding
(000).................................. 52,492 52,299 52,595
Basic and Diluted Earnings Per Share.... $ 1.42 $ 1.12 $ 1.55
Dividends Declared Per Share............ $ 1.54 $ 1.54 $ 1.54
Dividends Paid Per Share................ $ 1.54 $ 1.54 $ 1.54
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
45
ATLANTIC ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS, IN THOUSANDS)
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
---- ---- ----
Cash Flows of Operating Activities
Net Income................................ $ 74,405 $ 58,767 $ 81,768
Unrecovered Purchased Power Costs......... 17,136 16,417 15,721
Deferred Energy Costs..................... 6,105 (2,095) (20,435)
Depreciation and Amortization............. 83,950 81,595 79,232
Deferred Income Taxes-Net................. 993 6,192 25,946
Unrecovered State Excise Taxes............ 9,560 9,560 9,560
Employee Separation Costs................. (308) (7,179) (19,112)
Net Changes Working Capital Components:
Accounts Receivable & Unbilled Revenues.. (13,166) (5,004) (24,400)
Accounts Payable......................... (1,139) 5,651 (5,222)
Inventory................................ 3,362 (2,602) 4,960
Other.................................... (6,178) 11,503 (20,125)
Rate Refunds............................. (13,000) 13,000 --
Other-Net................................. 6,055 (2,653) 5,841
---------- ---------- ----------
Net Cash Provided by Operating
Activities............................... 167,775 183,152 133,734
---------- ---------- ----------
Cash Flows of Investing Activities
Utility Construction Expenditures......... (80,849) (86,805) (100,904)
Leased Nuclear Fuel Material.............. (9,105) (6,833) (10,446)
Nonutility Construction Expenditures...... (59,879) (25,451) (5,226)
Other-Net................................. (15,210) (14,783) (23,794)
---------- ---------- ----------
Net Cash Used by Investing Activities..... (165,043) (133,872) (140,370)
---------- ---------- ----------
Cash Flows of Financing Activities
Proceeds from Long Term Debt.............. 169,091 45,075 168,904
Retirement/Maturity of Long Term Debt..... (87,566) (12,266) (57,489)
Issuance of Preferred Securities of
Subsidiary Trust......................... -- 70,000 --
Increase in Short Term Debt............... 7,150 34,405 21,945
Repurchase of Common Stock................ -- -- (29,626)
Redemption of Preferred Stock-ACE......... (20,000) (98,876) (24,500)
Dividends Declared on Common Stock........ (80,856) (81,163) (81,088)
Proceeds-Capital Lease Obligations........ 9,105 6,833 10,466
Other-Net................................. 2,290 (3,701) (1,399)
---------- ---------- ----------
Net Cash (Used) Provided by Financing
Activities............................... (786) (39,693) 7,213
---------- ---------- ----------
Net Increase in Cash and Temporary
Investments.............................. 1,946 9,587 577
Cash and Temporary Investments:
Beginning of Year........................ 15,278 5,691 5,114
---------- ---------- ----------
End of Year.............................. $ 17,224 $ 15,278 $ 5,691
========== ========== ==========
Supplemental Schedule of Payments:
Interest.................................. $ 73,859 $ 68,551 $ 61,160
Income taxes.............................. $ 49,072 $ 28,101 $ 30,769
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
46
ATLANTIC ENERGY, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN
COMMON SHAREHOLDERS' EQUITY
(DOLLARS, IN THOUSANDS, EXCEPT SHARE DATA)
COMMON RETAINED UNEARNED
SHARES STOCK EARNINGS COMPENSATION
------ ------ -------- ------------
Balance, December 31, 1994......... 54,155,245 $593,475 $249,181 $(3,170)
---------- -------- -------- -------
Net Income......................... 81,768
Dividends on Common Stock.......... (81,208)
Common Stock Issued:
Equity Incentive Plan............. 9,234 (144) 162
ACE Plan.......................... (7,601) (163)
Common Stock Expenses............. (106)
Reacquired Shares.................. (1,625,000) (29,626)
---------- -------- -------- -------
Balance, December 31, 1995......... 52,531,878 563,436 249,741 (3,008)
---------- -------- -------- -------
Net Income......................... 58,767
Dividends on Common Stock.......... (81,163)
Common Stock Issued:
Equity Incentive Plan............. (555) (29) 285 26
ACE Plan.......................... (28,844) (567)
Common Stock Expenses............. (94)
---------- -------- -------- -------
Balance, December 31, 1996......... 52,502,479 562,746 227,630 (2,982)
---------- -------- -------- -------
Net Income......................... 74,405
Dividends on Common Stock.......... (80,856)
Common Stock Issued:
Equity Incentive Plan............. 2,000 794 588 2,982
Employee Stock Purchase Plan...... (144)
Common Stock Expenses............. (80)
---------- -------- -------- -------
Balance, December 31, 1997......... 52,504,479 $563,460 $221,623 $ --
========== ======== ======== =======
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
47
ATLANTIC ENERGY, INC. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Organization
Atlantic Energy, Inc. (the Company, AEI or parent) plans to merge with
Delmarva Power & Light Company (DP&L) into a new company named Conectiv, Inc.
(Conectiv) effective March 1, 1998. The Company is the parent of Atlantic City
Electric Company (ACE), Atlantic Energy Enterprises, Inc. (AEE) and Atlantic
Energy International, Inc. (AEII), which are wholly-owned subsidiaries. In
October 1997, the Company and DP&L entered into an agreement to form Conectiv
Solutions, LLC, a limited liability corporation to market and sell offerings
of energy and energy-related and other value-added services to large energy
users.
ACE is a public utility primarily engaged in the generation, purchase,
transmission, distribution and sale of electric energy. Sales of electric
energy include sales at regulated retail and unregulated wholesale levels.
ACE's service territory encompasses approximately 2,700 square miles within
the southern one-third of New Jersey with the majority of customers being
residential and commercial. ACE is the principal subsidiary within the
consolidated group.
AEE is a holding company which is responsible for the management of the
investments in the following nonutility companies: Atlantic Generation, Inc.
(AGI) is engaged in the development, acquisition, ownership and operation of
cogeneration power projects. AGI's activities are represented by partnership
interests in cogeneration facilities in New Jersey. Atlantic Southern
Properties, Inc. (ASP) owns and manages commercial offices and warehouse
facilities located in Atlantic County, New Jersey. ATE Investment, Inc. (ATE)
provides financing to affiliates and manages a portfolio of investments in
leveraged leases for equipment used in the airline and shipping industries.
ATE joined with an unaffiliated company to create EnerTech Capital Partners,
L.P. (Enertech), a limited partnership that invests in a variety of energy-
related technology growth companies. Atlantic Thermal Systems, Inc. (ATS) is
engaged in the development and operation of thermal heating and cooling
systems. CoastalComm, Inc. (CCI) is engaged in fiberoptic network development,
construction, and site services. AEE also has a 50% equity interest in
Enerval, LLC (Enerval) which provides energy management services, including
natural gas supply, transportation and marketing.
AEII was organized to pursue utility consulting services and equipment sales
to international markets. The Company is in the process of dissolving AEII.
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 and AEE consolidate their
respective subsidiaries. Ownership interests in other entities, between 20%
and 50%, where control is not evident, are accounted for using the equity
method of accounting.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires
management at times to make certain judgments, estimates and assumptions that
affect amounts and matters reported at the year end dates and for the annual
periods presented. Actual results could differ from those estimates. Any
change in the judgments, estimates and assumptions used, which in management's
opinion would have a significant effect on the financial statements, will be
reported when management becomes aware of such changes.
Reclassification
Certain prior year amounts have been reclassified to conform to the current
year reporting of these items. The most notable reclassification, with no
effect on net income, pertains to the Company's nonutility activities
48
previously reported in the Other Income line on the Consolidated Statement of
Income. The revenues, operating expenses and income taxes from those
operations are now reflected on the appropriate line items.
Regulation -- ACE
The accounting policies and rates of service for ACE are subject to the
regulations of the New Jersey Board of Public Utilities (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
as permitted by Statement of Financial Accounting Standards No. 71 "Accounting
for the Effects of Certain Types of Regulation" (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 was 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 are 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 assessment is made.(See
Note 12 -- Electric Utility Industry Restructuring and Stranded Costs for
further discussion about the effects of regulation in a competitive
environment). Specific regulatory assets and liabilities that have been
recorded are discussed in Note 13.
Operating Revenues
ACE'S electric operating revenues are recognized when electric energy
services are rendered, and include estimates for amounts unbilled at the end
of the period for energy used by customers subsequent to the last bill
rendered for the calendar year. ACE also records revenues for non-regulated
wholesale energy market sales transactions as they occur.
Other services revenues primarily represent revenues of ATS which are
recognized when heating and cooling services are rendered and include
estimates for amounts consumed by but not yet billed to customers at the end
of the period.
Nuclear Fuel -- ACE
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, Utility Plant is subject to
a first mortgage lien. The cost of property additions, including replacement
of units of property and betterments, are 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% for all periods.
Nonutility Property and Equipment
Nonutility Property and Equipment are generally stated at cost and includes
project development costs and construction work in progress, including
capitalized interest, related to the development and construction of
49
thermal heating and cooling systems of ATS. ASP's commercial sites, including
the cost of improvements and certain preacquisition costs are stated at the
lower of cost or fair market value. Capitalized interest related to nonutility
expenditures was $3.7 million for 1997.
Depreciation
ACE provides for straight-line depreciation based on the following:
transmission and distribution property -- estimated remaining life; nuclear
property -- remaining life of the related plant operating license in existence
at the time of the last base rate case; other depreciable property --
estimated average service life. ACE's overall composite rate of depreciation
was 3.3% for the last three years. Accumulated depreciation is charged with
the cost of depreciable property retired together with removal costs less
salvage and other recoveries.
ASP's facilities are being depreciated over a thirty-one and one-half year
life using the straight-line method. Land improvements are being depreciated
using an accelerated method over a fifteen year life. Furniture and equipment
are depreciated over lives ranging from three to seven years. ATS's Midtown
Energy Center and its components will be depreciated on a straight-line basis
over their respective useful lives starting in January 1998.
Nuclear Plant Decommissioning Reserve -- ACE
A reserve for decommissioning costs is presented as a component of
accumulated depreciation and amounted to $80.7 million and $70.2 million at
December 31, 1997 and 1996, respectively. The Securities and Exchange
Commission (SEC) has questioned certain accounting practices employed by the
electric utility industry concerning decommissioning costs for nuclear
generating facilities. In 1996, the FASB issued a Proposed Statement of
Financial Accounting Standard "Accounting for Certain Liabilities Related to
Closure or Removal of Long-lived Assets" which would establish accounting
standards for certain obligations that are incurred for the closure and
removal of long-lived assets. In January 1998, the FASB changed the title of
its project to "Accounting for Obligations Related to the Retirement of Long-
Lived Assets", which continues to include nuclear plant decommissioning costs.
Under the original proposed statement a regulated utility would recognize a
regulatory asset or liability for differences, if any, in the timing of
recognition of the costs of closure and removal of assets for financial
reporting purposes and rate making treatment. The Company cannot predict when
the FASB will issue a final accounting standard or the outcome of this matter
at this time.
Deferred Energy Costs -- ACE
As approved by the BPU, ACE has a Levelized Energy Clause (LEC) through
which energy and energy-related costs (energy costs) are charged to customers.
LEC rates are based on projected energy costs and prior period underrecoveries
or overrecoveries. Generally, energy costs are recovered through levelized
rates over the period of projection, which is usually 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 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.
License Fees
ATS has entered into agreements with six hotel casino's in Atlantic City,
New Jersey to operate their heating and cooling systems. As part of these
agreements, ATS has paid $27.5 million in fees to date, for the right to
operate and service such systems for a period of 20 years. These fees are
recorded on the balance sheet as License Fees and are being amortized over the
life of the agreements.
50
Income Taxes
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. Investment tax credits previously used for
income tax purposes have been deferred on the Consolidated Balance Sheet and
are 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.
Cash & Temporary Investments
AEI and ACE consider all highly liquid investments and debt securities
purchased with a maturity of three months or less to be cash equivalents.
Earnings Per Common Share
The FASB issued Statement No. 128, "Earnings Per Share" (SFAS No. 128) which
specifies the computation, presentation and disclosure requirements of
earnings per share for entities with publicly held common stock and potential
common stock. Earnings per share (EPS) presented on the face on the
consolidated income statement has been calculated to reflect the adoption of
SFAS No. 128 by the Company. Basic EPS is computed based upon the weighted
average number of common shares, excluding contingently issuable shares,
outstanding during the year. Diluted EPS is computed based upon the weighted
average number of common shares including contingently issuable shares and
other dilutive items. The difference between the 1997 basic and diluted EPS
reflects the effects of the EIP shares which are considered to be outstanding
throughout 1997 for the diluted EPS calculation. Contingently issuable shares
existed for all periods but were not included in the diluted EPS computation
for 1996 and 1995 because the restrictions were determined to not be met at
the end of the period. Options existed for 1996 and 1995 but were not included
as common stock equivalents in the dilutive calculation because they were
antidulitve. See Note 5 -- Benefits for further discussion of the EIP.
Other
Debt premium, discount and expense of ACE are amortized over the life of the
related debt. Premiums associated with the 1996 Preferred Stock redemptions
are being deferred and amortized over the life of the related ACE Obligated
Mandatorily Redeemable Preferred Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of ACE in accordance with BPU approval.
In June 1997, the FASB issued Statement No. 130 "Reporting Comprehensive
Income" and Statement No. 131 "Disclosure About Segments of an Enterprise and
Related Information". These statements are effective for fiscal years
beginning after December 15, 1997. Since these statements are primarily
disclosure related, the Company currently believes that they will not have a
significant effect on the Consolidated Financial Statements.
NOTE 2. INCOME TAXES
The components of Federal income tax expense for the years ended December 31
are as follows:
(000) 1997 1996 1995
---- ---- ----
Current....................................... $48,739 $27,061 $20,483
Deferred...................................... 1,217 6,587 25,993
Investment Tax Credits Recognized on Leveraged
Leases....................................... (136) (78) (28)
------- ------- -------
Total Federal Income Tax Expense.............. $49,820 $33,570 $46,448
======= ======= =======
51
A reconciliation of the expected Federal income taxes compared to the
reported Federal income tax expense computed by applying the statutory rate
for the years ended December 31 follows:
(000) 1997 1996 1995
---- ---- ----
Statutory Federal Income
Tax Rate............... 35 % 35 % 35 %
Income Tax Computed at
the Statutory Rate..... $45,166 $36,058 $49,995
Plant Basis
Differences............ 4,952 3,096 1,307
Amortization of
Investment Tax
Credits................ (2,670) (2,612) (2,562)
Other-Net............... 2,372 (2,972) (2,292)
------- ------- -------
Total Federal Income Tax
Expense................ $49,820 $33,570 $46,448
======= ======= =======
Effective Federal Income
Tax Rate............... 39 % 33 % 33 %
The increase in the effective Federal income tax expense rate is due
primarily to permanently non-deductible merger and merger related expenses.
State income tax expense is not significant.
Items comprising deferred tax balances as of December 31 are as follows:
(000) 1997 1996
---- ----
Deferred Tax Liabilities:
Plant Basis Differences................................. $332,288 $326,673
Leveraged Leases........................................ 76,362 76,671
Unrecovered Purchased Power Costs....................... 16,813 22,630
State Excise Taxes...................................... 16,326 20,141
Other................................................... 38,481 33,192
-------- --------
Total Deferred Tax Liabilities........................ 480,270 479,307
-------- --------
Deferred Tax Assets:
Deferred Investment Tax Credits......................... 23,775 25,143
Other................................................... 15,797 16,866
-------- --------
Total Deferred Tax Assets............................. 39,572 42,009
-------- --------
Total Deferred Taxes-Net................................ $440,698 $437,298
======== ========
At December 31, 1997 and 1996, deferred tax assets exist for cumulative
state income tax net operating loss (NOL's) carryforwards. At December 31,
1997 unexpired state NOL's amount to approximately $60.6 million, with
expiration dates from 1998 through 2004. As of December 31, 1997, deferred
state tax assets of $5.5 million offset by a valuation allowance of $4.0
million have been recorded.
On July 14, 1997 the Governor signed a bill into law eliminating the Gross
Receipts and Franchise Tax (GR & FT) paid by the electric, natural gas and
telecommunication public utilities. In its place, utilities will be subject to
the state's corporate business tax. In addition, the state's existing sales
and use tax will be expanded to include retail sales of electric power and
natural gas, and a transitional energy facility assessment tax (TEFA) will be
applied for a limited time on electric and natural gas utilities and will be
phased-out over a five year period. The law took effect January 1, 1998 and on
January 1 of each of the years thereafter, the TEFA will be reduced by 20%. By
the year 2003, the TEFA will be fully phased-out and the savings will be
passed through to ACE's customers. As a result of this law, ACE will record
deferred state taxes beginning in 1998 for state tax basis versus book basis
differences.
52
NOTE 3. RATE MATTERS OF ACE
ENERGY CLAUSE PROCEEDINGS
CHANGES IN LEVELIZED ENERGY CLAUSE RATES
1995 -- 1997
AMOUNT AMOUNT
DATE REQUESTED GRANTED DATE
FILED (MILLIONS) (MILLIONS) EFFECTIVE
----- ---------- ---------- ---------
4/95 $37.0 $37.0 7/95
3/96 49.7 27.6 7/96
2/97 20.0 -- --
ACE's LEC is subject to annual review by the BPU.
In July 1995, the BPU approved a provisional increase of $37 million in
annual LEC revenues for the period June 1, 1995 through May 31, 1996. The BPU
approved a continuance of the provisional increase in March 1996.
In March 1996, ACE requested a $49.7 million increase in 1996-1997 annual
revenues effective June 1, 1996. Through a stipulation reached and approved in
July 1996 among ACE, the New Jersey Division of the Ratepayer Advocate
(Ratepayer Advocate) and the Staff of the BPU (collectively, the parties), ACE
implemented provisional rates reflecting an increase of annual LEC revenues of
$27.6 million. The BPU approved a continuance of the provisional rates in
December 1996 when the Salem Station replacement power issues, among others,
were resolved.
In December 1996, the BPU issued an Order approving a stipulation of
settlement reached among the parties settling the issues regarding replacement
power costs related to an extended Salem Nuclear Generating station (Salem)
outage and a 1994 Salem Unit 1 outage. The stipulations provided that ACE's
replacement power costs for the Salem Station outage, up to each Unit's
agreed-upon return-to-service date (June 30, 1997 for Unit 1 and December 31,
1996 for Unit 2), and the 1994 Salem Unit 1 outage would be recoverable in LEC
rates implemented in ACE's next LEC filing.
In February 1997, ACE filed a petition with the BPU requesting an increase
in 1997-1998 annual LEC revenues of $20.0 million to be made effective for
service rendered on and after June 1, 1997. The increase requested is
primarily the result of ACE seeking recovery of previously deferred costs,
which includes recovery of the Salem Station replacement power costs in
accordance with the Orders issued in December 1996. In April 1997, ACE's
filing was transferred to the Office of Administrative Law and evidentiary
hearings have been completed. The administrative Law Judge's (ALJ) initial
decision is expected in the first quarter of 1998.
ACE expects to file a petition with the BPU during the first quarter of 1998
requesting an increase in 1998-1999 annual LEC revenues.
OTHER RATE PROCEEDINGS
On July 15, 1997, ACE filed its electric industry restructuring plan with
the BPU, as required by the Energy Master Plan, proposing ACE's plans to move
to retail access and the possible effect on rates. (See Note 12 -- ACE's
Electric Utility Restructuring and Stranded Costs).
In 1996, the BPU declared base rates associated with ACE's 7.41% ownership
in Salem interim and subject to refund. In December 1996, the BPU issued an
Order approving a stipulation of settlement reached among the parties
regarding the issue of base rates. In January and February 1997, in accordance
with the stipulation, ACE provided credits to customers totaling $12 million.
An additional credit of $1 million resolved an allegation previously made by
the Ratepayer Advocate that ACE, along with other New Jersey electric utility
companies, were recovering cogeneration capacity costs concurrently in base
rates and LEC rates.
53
In December 1997, the BPU approved an increase in annual base rate revenues
of $5.0 million for recovery of expenses associated with post-retirement
benefits other than pensions (OPEB). Also in a related action to this matter,
the BPU approved the request for a change in ownership to merge AEI into
Conectiv and found that an annual rate decrease of $15.8 million should be
provided to ACE's customers effective with the merger. The BPU ordered a pre-
merger credit of $5.0 million to offset the increase in rates associated with
OPEB. This increase was effective on January 1, 1998. See Notes 5 and 13 for
further information regarding OPEB expenses and the corresponding regulatory
asset and Note 4 for further information regarding the merger.
NOTE 4. MERGER
On August 12, 1996, the Boards of Directors of AEI and Delmarva Power &
Light Company (DP&L) jointly announced an agreement to merge the companies
into a new company named Conectiv, Inc. (Conectiv). Conectiv, a newly formed
Delaware corporation, became the parent of AEI's subsidiaries and the parent
of DP&L and its subsidiaries effective March 1, 1998. See discussions on
approvals below.
DP&L is predominately a public utility engaged in electric and gas service.
DP&L provides retail and wholesale electric service to customers located in
about a 6,000 square mile territory located in Delaware, eastern shore
counties in Maryland and the eastern shore area of Virginia. DP&L provides gas
service to retail and transportation customers in an area consisting of about
275 square miles in Northern Delaware, including the City of Wilmington.
The merger is to be a tax-free, stock-for-stock transaction accounted for
under the purchase method of accounting with DP&L as the acquirer. Under the
terms of the agreement, DP&L shareholders will receive one share of Conectiv's
common stock for each share of DP&L common stock held. AEI shareholders will
receive 0.75 shares of Conectiv's common stock and 0.125 shares of Conectiv's
Class A common stock for each share of AEI common stock held.
On January 30, 1997, the merger was approved by the shareholders of both
companies. Approvals have since been obtained from the FERC, Delaware and
Maryland Public Service Commissions, the Virginia State Corporate Commission,
the Pennsylvania Public Utilities Commission, the BPU and the Nuclear
Regulatory Commission (NRC). The last and final approval was received from the
SEC on February 26, 1998. The merger became effective March 1, 1998.
Under the terms of the BPU's approval of the merger, approximately 75
percent or $15.75 million of ACE's total average projected annual merger
savings will be returned to ACE's customers for an overall merger-related
reduction of 1.7 percent.
The total consideration to be paid to the Company's common stockholders,
measured by the average daily closing market price of the Company's common
stock for the three trading days immediately preceding and the three trading
days immediately following the public announcement of the merger, is $921.0
million. The consideration paid plus estimated acquisition costs and
liabilities assumed in connection with the merger are expected to exceed the
net book value of the Company's net assets by approximately $200.5 million,
which will be recorded as goodwill by Conectiv. The actual amount of goodwill
recorded will be based on the Company's net assets as of the merger date and,
accordingly, will vary from this estimate which is based on the Company's net
assets as of December 31, 1997. The goodwill will be amortized over 40 years.
54
Selected information on each company at December 31, 1997 and the year then
ended is shown below (in thousands, except for number of customers):
AEI DP&L
--- ----
(UNAUDITED)
Operating Revenues.................................. $1,102,360 $1,423,502
Net Income.......................................... $ 74,405 $ 105,709
Assets.............................................. $2,723,884 $3,015,481
Electric Customers.................................. 480,960 448,323
Gas Customers....................................... -- 103,248
Combination of the above amounts would not necessarily be reflective of the
amounts that would result from a consolidation of the companies.
On June 26, 1997, the Company and DP&L jointly announced an enhanced
retirement offer and separation program that will be utilized to achieve
workforce reductions as a result of the merger. The Company and DP&L initially
anticipated a combined loss of approximately 400 positions to accomplish the
merger-related rate reductions to customers. This initial level of reductions
will be achieved primarily through the DP&L early retirement and the Company's
enhanced retirement programs. Additional reductions are also anticipated to
better align staffing requirements to skill and work process needs. The
combined additional reductions could range between 250 to 350 positions. The
total cost to the Company for these programs, as well as the cost of executive
severance, employee relocation and facilities integration is estimated to
range from $38 million to $43 million. ACE is required to recognize these
costs through expense in accordance with GAAP. The actual cost to the Company
and ACE will depend on a number of factors related to the employee mix as well
as the actual number of employees who will be eligible for the enhanced
retirement or separation programs.
In the fourth quarter of 1997, the Company recorded an expense of $23.6
million as a result of terminating certain benefit programs of the Company in
anticipation of the merger. Termination of the plans resulted in charges of
$10.0 million for a supplemental executive retirement plan, $6.3 million due
to a pension plan curtailment, $3.8 million from the EIP and $3.5 million from
other benefit plans and executive contract terminations. See Note 5. below for
discussion of the effects on the defined pension plan and the EIP.
NOTE 5. BENEFITS
RETIREMENT BENEFITS -- ACE
Pension
ACE has a noncontributory defined benefit pension plan covering
substantially all of its employees. Benefits are based on an employee's years
of service and average final pay. ACE's policy is to fund pension costs within
the range of the minimum required by the Employee Retirement Income Security
Act and the maximum allowable as a tax deduction.
Net periodic pension costs include:
(000) 1997 1996 1995
---- ---- ----
Service cost -- benefits earned during the
period.................................... $ 6,763 $ 6,870 $ 6,363
Interest cost on projected benefit
obligation................................ 15,840 14,569 14,794
Actual return on plan assets............... (39,394) (36,443) (44,067)
Other -- net............................... 25,611 19,123 28,379
-------- -------- --------
Net periodic pension costs................. $ 8,820 $ 4,119 $ 5,469
======== ======== ========
55
Of these costs for 1997, $6.3 million was due to a curtailment as a result
of the lump-sum payments to certain plan participants who will terminate
employment effective with the consummation of the merger or shortly then
after. This amount is included in the Termination of Employee Benefit Plans
line item of the Consolidated Statement of Income. Of the remaining net
periodic payment costs, $1.9 million was charged to operating expense in 1997.
In 1996 and 1995 $3.0 million annually was charged to operating expense. The
remaining costs, which are associated with construction labor, were charged to
the cost of new utility plant. Actual return on plan assets and Other-net for
1997 and 1996 primarily reflect the favorable market conditions from the
investment of plan assets and expected returns.
A reconciliation of the funded status of the plan as of December 31 is as
follows:
(000) 1997 1996
---- ----
Fair value of plan assets............................ $259,500 $236,000
Projected benefit obligation......................... 239,000 207,340
-------- --------
Plan assets in excess of projected benefit
obligation.......................................... 20,500 28,660
Unrecognized net transition asset.................... (1,532) (1,377)
Unrecognized prior service cost...................... 232 259
Unrecognized net gain................................ (10,810) (18,958)
-------- --------
Prepaid pension cost................................. $ 8,390 $ 8,584
======== ========
Accumulated benefit obligation:
Vested benefits...................................... $207,102 $170,751
Nonvested benefits................................... 1,487 2,023
-------- --------
Total................................................ $208,589 $172,774
======== ========
At December 31, 1997, approximately 66% of plan assets were invested in
equity securities, 27% in fixed income securities and 7% in other investments.
The assumed rates used in determining the actuarial present value of the
projected benefit obligation at December 31 were as follows:
1997 1996 1995
---- ---- ----
Weighted average discount................................... 7.0% 7.5% 7.0%
Anticipated increase in compensation........................ 3.5% 3.5% 3.5%
Assumed long term rate of return............................ 9.0% 8.5% 8.5%
OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB)
ACE provides 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 ACE. 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.
Net periodic other postretirement benefit costs include:
(000) 1997 1996 1995
------- ------- -------
Service cost -- benefits attributed to service
during the period............................ $ 2,531 $ 2,688 $ 2,891
Interest cost on accumulated postretirement
benefits obligation.......................... 6,843 7,482 8,107
Actual return on plan assets.................. (800) (771) (1,437)
Amortization of unrecognized transition
obligation................................... 2,768 2,768 3,893
Other-net..................................... (475) 215 404
------- ------- -------
Net periodic other postretirement costs....... $10,867 $12,382 $13,858
======= ======= =======
56
These costs were allocated as follows:
(MILLIONS) 1997 1996 1995
---- ---- ----
Operating expense.......................................... $3.0 $3.6 $3.1
New utility plant-associated with construction labor....... 3.0 2.4 2.5
Regulatory asset........................................... 4.9 6.4 8.3
The regulatory asset represents the amount of annual costs in excess of the
amount of cost currently recovered in rates. These excess costs were deferred
as authorized by an accounting order of the BPU pending future recovery
through rates. ACE will begin to recover these costs over a 15 year period
beginning in 1998. See Note 3 and Note 13 for additional information.
A reconciliation of the funded status of the plan as of December 31 is as
follows:
(000) 1997 1996
-------- --------
Accumulated benefits obligation:
Retirees............................................. $ 51,786 $ 63,095
Fully eligible active plan participants.............. 6,075 4,038
Other active plan participants....................... 45,963 39,972
-------- --------
Total accumulated benefits obligation................ 103,824 107,105
Less fair value of plan assets....................... 20,100 18,000
-------- --------
Accumulated benefits obligation in excess of plan as-
sets................................................ 83,724 89,105
Unrecognized net loss................................ (4,727) (12,207)
Unamortized unrecognized transition obligation....... (41,521) (44,289)
-------- --------
Accrued other postretirement benefits cost obliga-
tion................................................ $ 37,476 $ 32,609
======== ========
At December 31, 1997, approximately 73% of plan assets were invested in
fixed income securities and 27% in other investments.
The assumed health care costs trend rate for 1998 is 7% and is assumed to
evenly decline to an ultimate constant rate of 5% in the year 2001 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 1997 net
periodic benefits cost would increase by $1.2 million, and the accumulated
postretirement benefits obligation at December 31, 1997 would increase by
$10.8 million. The weighted average discount rate assumed in determining the
accumulated benefits obligation was 7.0%, 7.5% and 7.0% for 1997, 1996 and
1995, respectively. The assumed long term return rate on plan assets was 7%
for each of the three year periods.
OTHER
Savings and Investment Plans A and B (401(k))
ACE has two 401(k) plans one for union and another for non-union employees
that match plan contributions up to 6% of a participating employee's base pay.
The rate at which Company contributions are made is 50%. All full and part-
time employees are eligible to participate. The cost of the plans for 1997,
1996 and 1995 was $2.0 million, $1.9 million and $1.9 million, respectively.
Equity Incentive Plan (EIP)--AEI
Eligible participants of the EIP 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
57
awards of restricted shares are based on attainment 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 which is subject
to the same award criteria.
Restricted stock activity of the EIP was as follows:
WEIGHTED
AVERAGE
RESTRICTED FAIR VALUE
SHARES GRANT DATE
---------- ----------
Balance, December 31, 1994........................... 175,712 20.975
Issued/Granted....................................... 24,435
Forfeited............................................ (7,587)
--------
Balance, December 31, 1995........................... 192,560 20.697
Issued/Granted....................................... 237,782
Forfeited............................................ (207,805)
--------
Balance, December 31, 1996........................... 222,537 19.160
Issued/Granted....................................... 22,255 17.376
Awarded.............................................. (244,792)
--------
Balance, December 31, 1997........................... -0-
========
The 1997, 1996 and 1995 restricted shares granted include 20,255 shares,
13,786 shares and 7,614 shares, respectively, purchased on the open market
from reinvestment of dividends on EIP shares outstanding. On November 13,
1997, the Board of Directors of the Company in accordance with the EIP
provisions with respect to a potential change in control declared that the
restrictions applicable to any of the Restricted Stock removed and shares
deemed fully vested. Distribution of the awards could be either in cash or
common stock, based on the election of the participant. The change in control
price was established at $19.50 per share. In the fourth quarter the Company
recognized $3.7 million in expense due to the termination of the plan with
respect to the restricted shares. Compensation expense for 1996 and 1995 for
the restricted stock has been measured based on the intrinsic value of the
stock. The total compensation expense for the years 1996 through 1995 amounted
to less than $.7 million and reflect an adjustment for the restricted shares
associated with the first three-year period that were not awarded and were
forfeited.
Option information is as follows:
1997 1996 1995
------------------------ ----------------------- -----------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
SHARES EXERCISE PRICE SHARES EXERCISE PRICE SHARES EXERCISE PRICE
OPTIONS ------ -------------- ------ -------------- ------ --------------
Beginning Balance....... 371,437 20.105 166,987 $21.125 167,300 $21.125
Granted................. 207,250 19.296 6,387 21.125
Forfeited............... (371,437) (2,800) 21.125 (6,700) 21.125
Ending Balance.......... -0- 371,437 20.105 166,987 21.125
Weighted
Average Fair value --
each.................. N/A $1.33 N/A
In addition, the Board took appropriate action with respect to the Stock
Options issued pursuant to the EIP. The Company recognized $.1 million in
expense due to the termination of the plan with respect to the options
forfeited under phase II of the EIP. The options associated with phase 1 of
the EIP Plan were forfeited because grant price exceeded the established
change in control price.
58
The combined effects of accounting for restricted shares and options under
the EIP plans consistent with the fair value disclosure requirements of SFAS
No. 123 upon the net income of the Company would have been a reduction in
expense of $.4 million in 1997 and an increase in expense of less than $.2
million in 1996. The effect of the application of SFAS No. 123 on basic and
diluted earnings per share for both 1997 and 1996 is less than one cent.
NOTE 6. JOINTLY-OWNED GENERATING STATIONS -- ACE
ACE owns jointly with other utilities several electric generating
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
ended, 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 7.51/164.0 7.41/164.0 5.00/52.0
(000)
Electric Plant in
Service:
1997................... $ 13,559 $ 34,304 $ 135,775 $ 237,281 $ 240,612
1996................... 13,275 34,489 130,011 218,603 240,079
Accumulated
Depreciation:
1997................... $ 3,840 $ 7,791 $ 58,501* $ 78,189* $ 74,108*
1996................... 3,609 7,333 54,854* 79,635* 68,286*
Construction Work in
Progress:
1997................... $ 209 $ 266 $ 8,714 $ 11,754 $ 1,281
1996................... 300 270 12,992 27,015 1,321
Operations and
Maintenance Expenses
(including fuel):
1997................... $ 5,145 $ 7,654 $ 28,520 $ 14,146 $ 10,593
1996................... 5,626 7,507 29,337 34,403 10,899
1995................... 5,143 7,252 29,647 28,306 10,360
Working Funds:
1997................... $ 44 $ 69 $ 3,693 $ 6,977 $ 3,617
1996................... 44 69 3,833 7,252 3,545
- --------
* Excludes Nuclear Decommissioning Reserve.
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 decrease in Operations and Maintenance for Salem
reflects the effects of the December 31, 1996 agreement ACE entered into with
Public Service Electric & Gas (PS) in its capacity as operator of Salem for
the purpose of limiting ACE's exposure to operation and maintenance expenses
to be incurred during calendar year 1997. See Note 11 for further information
concerning Salem Nuclear Generating Station.
NOTE 7. NONUTILITY COMPANIES
Principal assets of each of the subsidiary companies of AEE at December 31,
1997 were: AGI -- investments of approximately $18.7 million in cogeneration
facilities; ASP -- commercial real estate properties
59
with a net book value of $9.2 million; ATE -- leveraged lease investments of
$80.4 million and $10.2 million invested in EnerTech Capital Partners, L.P.;
ATS -- construction costs in thermal heating and cooling projects of $84.8
million.
Other financial information regarding the subsidiary companies is as
follows:
NET WORTH OPERATING REVENUES NET INCOME (LOSS)
--------- ------------------ -----------------
COMPANY 1997 1996 1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ---- ---- ----
(000)
AGI............ $22,000 $21,361 $ 1,471 $1,683 $1,578 $1,640 $ 979 $2,513
ASP............ (99) 561 998 758 687 (660) (1,773) (841)
ATE............ 17,010 11,139 683 707 772 231 71 (50)
ATS............ 10,394 2,498 19,816 6,845 1,315 1,896 311 (213)
CCI............ 948 544 806 -- -- 126 (18) --
AGI's results in each year primarily reflect the equity in earnings of
cogeneration facilities in which AGI has an ownership interest. AGI's 1996
results reflect the contingency of a $1.6 million net of tax loss from the
sale of a cogeneration facility located in New York.
ASP's results in each year reflect the vacancy in its commercial site due to
generally poor market conditions in commercial real estate. Additionally, 1996
includes a net after tax write-down of the carrying value of the commercial
site of $0.8 million.
ATE's 1997 net income reflects reductions in interest expense and an income
tax benefit offset in-part by a $0.9 million after tax loss in ATE's
investment in Enertech Capital Partners, L.P.
ATS's 1997 results reflect earnings generated from the operation and
maintenance of customer heating and cooling facilities, offset in-part by
increased amortization and interest expense related to the license fees. ATS's
1996 results primarily reflect administrative and general costs for business
development and construction of heating and cooling systems. See Note 1 --
License Fees for further discussion.
AEI and AEE parent-only operations, excluding equity in the results of
subsidiary companies, generally reflect administrative and general expenses
for management of their respective subsidiaries.
AEI incurred losses of $4.1 million and $3.6 million in 1997 and 1996,
respectively. AEI's 1997 results reflect increased interest expense in
addition to a $.5 million after tax loss from the investment in Conectiv
Solutions, LLC. AEI's 1996 results reflect the impact of merger-related costs
and interest charges. The interest charges which affect all three years of
operation are associated with a line of credit established to fund certain
affiliated capital needs, the repurchase of common stock and general corporate
purposes.
AEE incurred losses of $4.9 million and $1.7 million in 1997 and 1996,
respectively. AEE's 1997 results include an after-tax loss of $2.2 million
from its equity investment in Enerval and a $0.9 million charge for the
Termination of Employee Benefit Plans. AEE's 1996 activity reflects an after
tax loss of $1.1 million from its investment in Enerval due to a combination
of unhedged gas sales agreements and higher spot market prices.
NOTE 8. CUMULATIVE PREFERRED SECURITIES OF ACE
The embedded cost of ACE Preferred Securities as of December 31, 1997, 1996
and 1995 was 7.5%, 7.4% and 7.4%.
At December 31, 1997, the minimum annual sinking fund requirements of the
Cumulative Preferred Stock Subject to Mandatory Redemption over the next five
years are $10 million for 1998 and $11.5 million for 2001 and 2002.
60
CUMULATIVE PREFERRED STOCK
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
1997 1996 OPTIONAL
PAR --------------- --------------- REDEMPTION
VALUE SHARES (000) SHARES (000) PRICE
SERIES ----- ------ ----- ------ ----- ----------
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
------- -------
Total.................... $30,000 $30,000
======= =======
Subject to Mandatory
Redemption:
$8.20...................... None 100,000 10,000 300,000 30,000 --
$7.80...................... None 239,500 23,950 239,500 23,950 --
------- -------
Total.................... 33,950 53,950
Current Portion.............. -- 10,000
------- -------
Total.................... $33,950 $43,950
======= =======
Cumulative Preferred Stock Not Subject to Mandatory Redemption is redeemable
solely at the option of ACE. If preferred dividends are in arrears for at
least a full year, preferred stockholders have the right to elect a majority
of directors to the Board of Directors until all dividends in arrears have
been paid.
On August 1, 1997 ACE redeemed 200,000 shares of its $8.20 Series No Par
Preferred Stock. Under a mandatory sinking fund requirement 100,000 shares
were required to be redeemed and ACE elected to redeem an optional 100,000
additional shares for a total of $20.0 million using short term debt.
Beginning May 1, 2001, 115,000 shares of the remaining $7.80 No Par
Preferred Stock must be redeemed annually through the operation of a sinking
fund at a redemption price of $100 per share. ACE has the option to redeem up
to an additional 115,000 shares without premium on any annual sinking fund
date.
ACE reclassified to long term $10.0 million of preferred stock due in 1998
due to the January 12, 1998 issuance of Medium Term Notes that will, in part,
be used to redeem the balance of it's $8.20 Series No Par Preferred Stock in
May 1998. (See Note 9)
ACE OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY TRUST
HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF ACE.
Atlantic Capital I, a grantor trust, is the issuer of $70 million (2,800,000
shares) of 8.25% Cumulative Quarterly Income ACE Obligated Mandatorily
Redeemable Preferred Securities with a stated liquidation preference of $25
each outstanding at December 31, 1997 and 1996. Atlantic Capital's sole
investment is ACE's 8.25% Junior Subordinated Deferrable Interest Debentures
(Junior Debentures). ACE reserves the right to defer payment of interest on
the debentures for up to 20 consecutive quarters. During such a deferral
period, certain dividend restrictions would apply to ACE's Common and
Preferred stock. The transactions of the trust are consolidated into the
financial statements of ACE, the Junior Debentures are eliminated in
consolidation.
61
NOTE 9. DEBT
DECEMBER 31,
MATURITY ------------------
SERIES DATE 1997 1996
- ------ -------- ---- ----
(000)
Secured Debt:
Medium Term Notes Series B (6.28%)................ 2/1/1998 $ 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
Medium Term Notes Series C (6.86%)................ 2001 40,000 40,000
7 1/2% First Mortgage Bond........................ 4/1/2002 -- 20,000
Medium Term Notes Series C (7.02%)................ 2002 30,000 30,000
Medium Term Notes Series B (7.18%)................ 2003 20,000 20,000
7 3/4% First Mortgage Bonds....................... 6/1/2003 -- 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
Medium Term Notes Series C (7.15%)................ 2004 9,000 9,000
Medium Term Notes Series B (6.45%)................ 2005 40,000 40,000
6 3/8% Pollution Control Series................... 12/1/2006 2,425 2,500
Medium Term Notes Series C (7.15%)................ 2007 1,000 1,000
Medium Term Notes Series B (6.76%)................ 2008 50,000 50,000
Medium Term Notes Series C (7.25%)................ 2010 1,000 1,000
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
Variable Rate Pollution Control Series A.......... 2014 18,200 --
Medium Term Notes Series C (7.63%)................ 2014 7,000 7,000
Medium Term Notes Series C (7.68%)................ 2015 15,000 15,000
Medium Term Notes Series C (7.68%)................ 2016 2,000 2,000
8 1/4% Pollution Control Series A................. 7/15/2017 -- 4,400
Variable Rate Pollution Control Series B.......... 2017 4,400 --
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 23,150
7.20% Pollution Control Series A.................. 11/1/2029 25,000 25,000
7% Pollution Control Series B..................... 11/1/2029 6,500 6,500
-------- --------
752,540 802,591
-------- --------
Unsecured Debt:
6.46% Medium Term Notes Series A.................. 4/1/2002 20,000 --
6.63% Medium Term Notes Series A.................. 6/2/2003 30,000 --
7.52% Medium Term Notes Series A.................. 4/2/2007 5,000 --
7.50% Medium Term Notes Series A.................. 4/2/2007 10,000 --
--------
65,000 --
--------
Debentures:
7 1/4%............................................ 5/1/1998 2,500 2,600
-------- --------
2,500 2,600
-------- --------
Amortized Premium and Discount -- Net............. (2,721) (2,771)
-------- --------
Total Long Term Debt -- ACE....................... 817,319 802,420
Add Short Term Debt to be Refinanced.............. 16,425 --
Less Current Portion.............................. -- (175)
-------- --------
Long Term Debt -- ACE............................. $833,744 $802,245
======== ========
Long Term Debt -- ACE............................. 833,744 802,245
Long Term Debt -- AEI............................. 53,500 37,575
Long Term Debt -- ATE............................. 20,000 33,500
Long Term Debt -- ATS............................. 120,066 54,500
-------- --------
Less Portion Due within One Year.................. 147,566 98,075
-------- --------
Total AEI Noncurrent Long-Term Debt............. 879,744 829,745
======== ========
62
Secured Medium Term Notes have varying maturity dates and are shown with the
weighted average interest rate of the related issues within the year of
maturity. Substantially all of ACE's utility plant is subject to the lien of
the Mortgage and Deed of Trust dated January 15, 1937, as amended and
supplemented, collateralizing ACE's First Mortgage Bonds.
ACE
ACE had authority to issue $150 million in short term debt, comprised of
$100 million of committed lines of credit and $50 million on a when offered
basis. At December 31, 1997 ACE had $77.9 million of unused short-term
borrowing capacity. ACE's weighted daily average interest rate on short term
debt was 5.8% for 1997 and 5.6% for 1996.
On May 1, 1997, ACE satisfied the sinking fund requirements of $100,000 for
its 7 1/4% Debentures and on December 1, 1997 satisfied the sinking fund
requirement of $75,000 for its 6 3/8% Pollution Control Series due December 1,
2006.
On July 30, 1997, ACE issued $22.6 million aggregate principal amount of
variable rate, tax-exempt pollution control bonds in two separate series:
$18.2 million Pollution Control Revenue Refunding Bonds, 1997 Series A due
April 15, 2014 (Series A) and $4.4 million Pollution Control Revenue Refunding
Bonds, 1997 Series B due July 15, 2017 (Series B). The Series A and the Series
B bonds paid an initial weekly rate of 3.4% and 3.5%, respectively. Each
subsequent rate is determined by the remarketing agent. The proceeds from the
sale of the Series A and Series B bonds were applied to the September 2, 1997
redemption of $18.2 million aggregate principal amount of 7 3/8% Pollution
Control Revenue Bonds of 1984, Series A and $4.4 million aggregate principal
amount of 8 1/4% Pollution Control Revenue Bonds of 1987, Series B. Aggregate
premiums paid for the September 2, 1997 redemption were $546,000 and $88,000,
respectively.
During 1997, ACE issued and sold $65 million aggregate principal amount of
Unsecured Medium Term Notes. Primarily, the notes were sold to cover the
December 1, 1997 redemption of $20 million principal amount of 7.5% First
Mortgage Bonds due April 1, 2002 and $29.976 million principal amount of 7.75%
First Mortgage Bonds due June 1, 2006. Aggregate premiums paid for the
redemption of these bonds were $240,000 and $440,647 respectively.
On January 12, 1998, ACE issued $85 million of Secured Medium Term Notes,
Series D maturing in January 2003 and January 2006. The Bonds paid a fixed
interest rate of 6.0%, 6.2% and 6.2%. The net proceeds to be received by the
Company from the issuance and sale of the Medium Term Notes will be applied to
the repayment of outstanding short-term and long-term indebtedness, including
the redemption of certain series of First Mortgage Bonds and Debentures
($58.575 million), Preferred Stock ($10 million) and unsecured short-term debt
($16.425 million) due in 1998.
At December 31, 1997, 1996 and 1995, ACE's embedded cost of long term debt
was 7.3%, 7.5% and 7.5%, respectively.
AEE
Long term debt of ATE includes $15 million of 7.44% Senior Notes due 1999.
ATE also has a revolving credit and term loan agreement which provides for
borrowings of up to $25 million during successive revolving credit and term
loan periods through June 1998. There were $5 million and $18.5 million in
borrowings outstanding under this agreement at December 31, 1997 and 1996,
respectively. Interest rates on borrowings are determined by reference to
periodic pricing options available under the facility. Interest on the
borrowings outstanding during 1997 ranged from 5.9% to 6.5%. This credit
facility will be available up until the effective date of the merger.
In December 1995, ATS through a partnership, arranged for the issuance of
$12.5 million of special, limited obligation bonds of the New Jersey Economic
Development Authority (NJEDA). Proceeds from the sale of the
63
bonds were placed in escrow. The proceeds may be released to the ATS
partnership and used to pay certain "qualified costs" subject to satisfaction
of certain conditions. In November 1997, ATS satisfied the escrow release
conditions and remarketed, through underwriters, $12.5 million principal
amount, Series 1995 Thermal Energy Facilities Revenue Bonds due December 1,
2009 at variable rates of interest. Since issuance, the interest rates to the
ATS partnership have ranged from 2.5% to 4.1%. In addition, the NJEDA issued
an additional $18.5 million in limited obligation bonds which were sold,
through underwriters, as Series 1997 Thermal Energy Facilities Revenue Bonds
due December 1, 2031 at variable rates which have ranged from 2.5% to 4.1%.
ATS applied $20.0 million of bond proceeds to reimburse it for certain
qualifying costs incurred during construction of the Midtown Energy Center in
Atlantic City, New Jersey. Proceeds of $11.0 million remained in escrow at
December 31, 1997 pending verification of compliance with NJEDA
qualifications.
ATS's $100 million revolving credit and term loan facility, was amended and
restated to $143 million in October 1997. Up to $50 million of available
credit commitment can be used to establish letters of credit. As of December
31, 1997 and 1996, $89.1 million and $42.0 million was outstanding under this
facility, respectively. Interest rates on borrowings are based on periodic
pricing options selected by ATS. Interest rates on the borrowings outstanding
ranged from 5.8% to 8.5% in 1997. This facility has been primarily used for
construction of the Midtown Energy Center, which began commercial operation in
January 1998. Aggregate commitment fees on unused credit lines of revolving
AEE credit agreements were not significant. This credit facility will be
available up until the effective date of the merger.
AEI
Under AEI's $75 million revolving credit and term loan facility, AEI had
$53.5 million and $37.6 million outstanding in borrowings at December 31, 1997
and 1996, respectively. Interest rates are based on periodic pricing options
selected by AEI. Interest on the borrowings outstanding during 1997 ranged
from 5.79% to 8.62%. This facility, has been used to fund acquisitions of
Company common stock and other general corporate purposes and will continue to
be used for corporate purposes up until the effective date of the merger.
LONG TERM DEBT
MATURITIES AND SINKING FUND REQUIREMENTS
ACE ATE AEI ATS TOTAL
(000) --- --- --- --- -----
1998............................. --* $ 5,000 $53,500 $89,066 $147,566
1999............................. $30,075 15,000 -- -- 45,075
2000............................. 46,075 -- -- -- 46,075
2001............................. 40,075 -- -- -- 40,075
2002............................. 50,075 -- -- -- 50,075
- --------
* Excludes amounts refinanced in 1998.
NOTE 10. 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), the EIP and the Employee Stock Purchase Plan (ESPP). The number of
shares of Common Stock issued (forfeited) during the year ended December 31,
and the number of shares reserved for issuance at December 31, 1997, were as
follows:
1997 1996 1995 RESERVED
---- ---- ---- --------
ACE Plans................................. -- (28,844) (7,601) 177,483
EIP....................................... 2,000 (555) 9,234 --
ESPP...................................... 51,133 -- -- 348,867
------ ------- ------
Total................................... 53,133 (29,399) 1,633
====== ======= ======
64
In April 1996, the shareholders of AEI approved the ESPP. Under this plan,
eligible employees can purchase shares of common stock at a 15% discount. The
offering periods begin on August 15 in each of the years 1996-1999 and end
August 14 of the following year. The maximum number of shares that shall be
issued under this plan shall be 100,000 in each of the offering periods plus
unissued shares from the prior offering period up to a total of 400,000
shares. On August 14, 1997 in lieu of issuing shares the Company bought 51,133
shares at a market price ranging from $17.625 to $18.00 per share, for $.9
million. This plan will terminate at the effective date of the merger.
The Company's program to reacquire up to three million shares of it's common
stock outstanding will expire with the merger. During 1995, the Company
reacquired and cancelled 1,625,000 shares for a total cost of $29.6 million
with prices ranging from $17.625 to $18.875 per share. As of December 31,
1997, the Company has reacquired and cancelled 1,846,700 shares of its common
stock at a total cost of $33.5 million. The Company did not reacquire and
cancel any shares under this program during 1997 or 1996.
Pursuant to ACE's certificate of incorporation, ACE is subject to certain
limitations on the payment of dividends to the Company, which is the holder of
all of ACE's common stock. When full dividends have been paid on the Preferred
Stock Securities of ACE for all past quarterly-yearly dividend periods,
dividends may be declared and paid by ACE on its common stock, as determined
by the Board of Directors of ACE, out of funds legally available for the
payment of dividends.
NOTE 11. COMMITMENTS AND CONTINGENCIES
CONSTRUCTION PROGRAM
ACE cash construction expenditures for 1998 are estimated to be
approximately $68 million. Nonutility capital expenditures for 1998 are
estimated to be $49 million.
PURCHASED CAPACITY AND ENERGY ARRANGEMENTS -- ACE
ACE arranges with various providers of bulk energy to obtain sufficient
supplies of energy to satisfy current and future energy requirements of the
Company. Arrangements may be for generating capacity and associated energy or
for energy only. Terms of the arrangements vary in length to enable ACE to
optimally manage its supply portfolio in response to changing market
conditions. At December 31, 1997, ACE has contracted for 2,416 megawatts (MWs)
of purchased capacity with terms remaining of 1 to 27 years and additionally,
125 MWs commencing in 1998 for 2 years and 175 MWs commencing in 1999 for 10
years. Information regarding these arrangements relative to ACE was as
follows:
1997 1996 1995
---- ---- ----
As a % of Capacity (year end)...................... 29% 30% 30%
As a % of Generation............................... 54% 55% 52%
Capacity charges (millions)........................ $197.4 $195.7 $190.6
Energy charges (millions).......................... $136.8 $145.1 $135.4
Amounts for purchased capacity are shown on the Consolidated Statement of
Income as Purchased Capacity. Of these amounts, charges of certain nonutility
providers are recoverable through the LEC, which amounted to $165 million,
$165.3 million and $162.7 million in 1997, 1996 and 1995, respectively.
Minimum future payments for purchased capacity and energy under contract for
the years 1998 through 2002 are performance driven and cannot be reasonably
estimated.
ENVIRONMENTAL MATTERS -- ACE
The provisions of Title IV of the Clean Air Act Amendments of 1990 (CAAA)
require, among other things, phased reductions of sulfur dioxide (SO/2/)
emissions by 10 million tons per year, a limit on SO/2/ emissions nationwide
by the year 2000 and reductions in emissions of nitrogen oxides (NOx) by
approximately 2 million
65
tons per year. ACE's wholly-owned B.L. England Units 1 and 2 and its jointly-
owned Conemaugh Units 1 and 2 are in compliance with Phase I requirements as
the result of installation of scrubbers at each station. All of ACE's fossil-
fuel steam generating units are affected by Phase II (2000) of the CAAA. A
compliance plan for these units currently reflects capital expenditures of
approximately $8.5 million in 1998 through 2002. The jointly-owned Keystone
Station is impacted by the SO/2/ and NOx provisions of Title IV of the CAAA
during Phase II. The Keystone owners plan to primarily rely on emission
allowances to comply with the CAAA through the year 2000.
On August 1, 1997, the New Jersey Department of Environmental Protection
(NJDEP) announced that it intended to introduce rules to reduce NOx emissions
by 90% from the 1990 levels by the year 2003. On September 15, 1997 the NJDEP
filed its proposal with the Office of Administrative Law. In its proposal,
entitled "NOx Budget Program", the NJDEP prescribed participation of New
Jersey's large combustion sources in a regional cap and trade program designed
to significantly reduce emissions of NOx. In effect, the proposed regulation
would require New Jersey to become the first northeastern state to require NOx
reductions of 90% from the 1990 levels, by the year 2003. Both ACE's B.L.
England and Deepwater generating stations will be affected by the NJDEP's
proposal. On October 24, 1997 ACE testified in opposition to the proposal. ACE
cannot predict the ultimate outcome of this matter or the costs of compliance.
OTHER
AEE provides payment guarantees to certain natural gas suppliers and
transporters of Enerval. These payment guarantee notifications provide that if
Enerval does not make timely payment as specified in an agreement with the
supplier or transporter, the Guarantor (AEE) will pay the amount due. The
amounts due vary from month to month with respect to purchases from and
payments to these suppliers and transporters. The exposure to AEE at December
31, 1997 was approximately $5.5 million.
The Company is party to various other claims, legal actions and complaints
arising in the ordinary course of business. In management's opinion, the
ultimate disposition of these matters will not have a material adverse effect
on its financial condition or results of operations.
NUCLEAR -- ACE
Nuclear Plant Decommissioning -- ACE
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, the dates that
decommissioning activities are expected to begin and return to be earned by
the assets of the fund. The present value of ACE's nuclear decommissioning
obligation, based on costs adopted by the BPU in 1991 and restated in 1997
dollars, is $164.8 million. Decommissioning activities as approved by the BPU
are expected to begin in 2006 and continue through 2032. The total estimated
value of the trust at December 31, 1997, inclusive of the present value of
future funding, based on current annual funding amounts and expected
decommissioning dates approved by the BPU, is approximately $147 million,
without earnings on or appreciation of the fund assets. In accordance with BPU
regulations, updated site-specific studies based on 1995 costs were completed
in September 1996 and submitted to the BPU for review by the Staff of the BPU
and the Ratepayer Advocate. The updated site specific studies support that the
current level of funding is sufficient. As such, ACE will not seek to increase
the recovery of decommissioning in its rates.
Salem Nuclear Generating Station
ACE is an owner of 7.41% of Salem Units 1 and 2, which are operated by PS.
The Salem units represent 164 MWs of ACE's total installed capacity of 2,415.7
MWs. Salem Unit 1 has been out of service since May 16, 1995. Salem Unit 2,
out of service since June 7, 1995 returned to service on August 30, 1997 and
reached 100% power on September 23, 1997.
66
PS has advised ACE that the installation of Salem Unit 1 steam generators
has been completed. The cost of purchasing and installing the steam
generators, as well as the disposal of the old generators is $186 million, of
which ACE's share is $13.8 million. The unit is currently expected to return
to service near the end of the first quarter of 1998. Restart of Salem Unit 1
is also subject to NRC approval.
The Salem Station outages has caused ACE to incur replacement power costs of
approximately $700 thousand per month per unit. As previously discussed, ACE's
replacement power costs for the current and recent outage, up to the agreed-
upon return-to-service date of June 30, 1997 for Salem Unit 1 and December 31,
1996 for Salem Unit 2, will be recoverable in rates in ACE's 1997 LEC
proceeding. Replacement power costs incurred after the agreed-upon return-to-
service date for the Salem Station will not be recoverable in rates. ACE has
incurred $10.2 million in non-recoverable replacement power costs to date
related to Salem.
ACE entered into an agreement with PS for the purpose of limiting ACE's
exposure to Salem's 1997 operation and maintenance (O&M) expenses. Pursuant to
the terms of the agreement, ACE was obligated to pay to PS $10 million of O&M
expense, as a fixed charge payable in twelve equal installments beginning
February 1, 1997. ACE's obligation for any contributions, above the $10
million, to Salem 1997 O&M expenses up to ACE's estimated share of $21.8
million, is based on performance and directly related to the timely return and
operation of the units. As a result of this Agreement, ACE agreed to dismiss
the complaint filed in the Superior Court of New Jersey in March 1996 alleging
negligence and breach of contract.
On February 27, 1996, the Salem co-owners filed a Complaint in United States
District Court for the District of New Jersey against Westinghouse Electric
Corporation, the designer and manufacturer of the Salem steam generators,
under Federal and state statutes alleging fraud, negligent misrepresentation
and breach of contract. The litigation is continuing in accordance with the
schedule established by the court.
Other
The Energy Policy Act of 1992 permits the Federal government to assess
investor-owned electric utilities that have ownership interests in nuclear
generating facilities for the decontamination and decommissioning of Federally
operated nuclear enrichment facilities. Based on its ownership in five nuclear
generating units, ACE has a liability of $4.6 million and $5.3 million at
December 31, 1997 and 1996, respectively, for its obligation to be paid over
the next 12 years. ACE has an associated regulatory asset of $5.0 million and
$5.7 million at December 31, 1997 and 1996, 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.
ACE is subject to a performance standard for its five jointly-owned nuclear
units. This standard is used by the BPU in determining recovery of replacement
energy costs when output from the nuclear units is reduced or not available.
Underperformance results in penalties which are not permitted to be recovered
from customers and are charged against income. According to a December 1996
stipulation agreement, the performance of Salem Units 1 and 2 shall not be
included in the calculation of a nuclear performance penalty for the period
each unit was taken out of service up to each unit's respective return-to-
service date. The parties to the stipulation agreed that for the years 1995
and 1996, there will be no penalty under the nuclear performance standard.
Additionally, ACE will not incur a nuclear performance penalty for 1997.
INSURANCE PROGRAMS -- ACE
Nuclear
ACE is a member of certain insurance programs that provide coverage for
contamination 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.
67
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, 1997, the
maximum amount of retrospective premiums ACE could be assessed for losses
during the current policy year was $4.4 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
reactor per incident, payable at $10 million per year. Based on its ownership
share of nuclear facilities, ACE could be assessed up to an aggregate of $27.6
million per incident. This amount would be payable at an aggregate of $3.48
million per year, per incident.
Other
ACE's comprehensive general liability insurance provides pollution liability
coverage, subject to certain terms and limitations 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.
NOTE 12. ACE'S ELECTRIC UTILITY INDUSTRY RESTRUCTURING AND STRANDED COSTS
In April 1997, the BPU issued its Final Report containing findings and
recommendations on the electric utility industry restructuring in New Jersey
to the Governor and the State Legislature for their consideration. The
recommendation for phase-in of retail choice to electric consumers calls for
choice to 10% of all customers beginning October 1, 1998 and to 100% by July
1, 2000. The Report required each electric utility in the state to file
complete restructuring plans, stranded cost filings and unbundled rate filings
by July 15, 1997. The Report would allow utilities the opportunity to recover
stranded costs on a case-by-case basis, with no guarantee of 100 percent
recovery of eligible stranded costs.
ACE filed its response to the BPU on July 15, 1997. ACE's restructuring plan
met the BPU's recommendations for phase-in of retail electric access based on
a first-come, first-served basis, proposing choice to 10% of all customers
beginning October 1, 1998 and to 100% by July 1, 2000. Customers remaining
with ACE will be charged a market-based electricity price beginning October 1,
1998. The restructuring plan included a two-phased approach to future rate
reductions.
In an October 31, 1997 letter to the BPU, ACE added specificity to the
framework set out in the restructuring plan with regard to steps ACE
anticipates taking to meet the BPU's rate reduction and restructuring goals.
First, specific, definable cost reductions of approximately 4% after 1998 were
outlined. Further, ACE offered that an appropriate resolution of the merger
proceedings will allow ACE to reduce its rates, due to the merger,
approximately 1.25% upon consummation of the change in control. In addition,
ACE's current estimate showed that, through the use of securitized debt for
the full amount of stranded costs associated with its own generation assets, a
further rate decrease of up to 2% was possible based on appropriate
legislation and orders of the BPU with respect to securitization. Finally, ACE
estimates that the results of good-faith negotiations with
68
the nonutility generators could provide a reduction of up to an additional
1.75%. In summary, ACE outlined a total rate reduction of 9% by the end of the
transition. On January 28, 1998, the BPU issued its Order establishing the
procedural schedule regarding the restructuring plan. Under that order,
hearings on the restructuring plan are to be completed by mid-May 1998. It is
anticipated that the BPU will issue its final order during the summer of 1998.
Under the stranded cost filing, ACE specified its total stranded cost
estimated to be approximately $1.3 billion, of which $911 million is
attributable to above-market nonutility generation (NUG) contracts. The
remaining amount, approximately $415 million, is related to wholly- and
jointly-owned generation investments. The stranded cost filing supports full
recovery of stranded costs, which ACE believes is necessary to move to a
competitive environment. On February 5, 1998, the Company filed rebuttal
testimony in the stranded cost filing. As part of the filing, the Company
updated its stranded cost estimates for the effects of tax law changes in the
State of New Jersey and to modify certain assumptions made in estimating the
stranded costs. The total stranded costs in the rebuttal filing are
approximately $1.2 billion with $812 million attributable to NUG contracts and
$397 million related to wholly- and jointly-owned generation investments.
Determination of the stranded cost filing will be heard by the Office of
Administrative Law. The ALJ is expected to render a decision in May 1998. If
ACE is required to recognize amounts as unrecoverable, ACE may be required to
write down asset values, and such writedowns could be material.
ACE continues to meet the criteria set forth in SFAS 71 and has presented
these financial statements in accordance therewith. (See Note 1 --
Regulation -- ACE). The FASB, through the Emerging Issue Task Force (EITF),
has recently set forth guidance intended to clarify the accounting treatment
of specific issues associated with the restructuring of the electric utility
industry through EITF Issue No. 97-4, "Deregulation of the Pricing of
Electricity -- Issues Related to the Application of FASB Statements No. 71,
Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises-Accounting for the Discontinuation of application of
FASB Statement No. 71" (EITF No. 97-4)". The consensus reached in EITF No. 97-
4 as to when an enterprise should stop applying SFAS 71 to a separable portion
of its business whose pricing is being deregulated, is defined as "when
deregulatory legislation or a rate order (whichever is necessary to effect
change in the jurisdiction) is issued that contains sufficient detail for the
enterprise to reasonably determine how the transition plan will effect the
separable portion of its business" (e.g. generation).
Consensus was also reached "that the regulatory assets and regulatory
liabilities that originated in the separable portion of an enterprise to which
Statement 101 (SFAS 101, "Regulatory Enterprises -- Accounting for the
Discontinuation of Application of FASB Statement No. 71") is being applied
should be evaluated on the basis of where (that is, the portion of the
business in which) the regulated cash flows to realize and settle them,
respectively, will be derived." Additionally, the "source of the cash flow
approach adopted in the consensus should be used for recoveries of all costs
and settlements of all obligation (not just for regulatory assets and
regulatory liabilities that are recorded at the date Statement 101 is applied)
for which regulated cash flows are specifically provided in the deregulatory
legislation or rate order".
At this time ACE cannot predict, with certainty when it will stop applying
SFAS 71 for its generation business. ACE also cannot predict the impacts for
its generation business nor can it predict the impacts on its financial
condition as a result of applying SFAS 101. The outcome will be dependent upon
when a plan is approved and the level of recovery of stranded costs allowed by
the BPU. If assets require a write-down as a result of the application of SFAS
101, ACE may need to record an extraordinary noncash charge to operations that
could have a material impact on the financial position and results of
operations of ACE.
ACE has entered into BPU approved Off-Tariff Rate Agreements (OTRA's) with
at-risk customers which provide for special rates for customers who may choose
to leave ACE's energy system because they have alternative energy sources
available. The aggregate amount of such reduced rate agreements has been a
reduction to revenues of $10.5 million for 1997 and $3.5 million for 1996.
69
NOTE 13. REGULATORY ASSETS AND LIABILITIES -- ACE
Costs incurred by ACE that have been permitted, or are expected to be
permitted, by the BPU to be deferred for recovery in rates in more than one
year, or for which future recovery is probable, are recorded as regulatory
assets. Regulatory assets are amortized to expense over the period of
recovery.
Total regulatory assets at December 31 are as follows:
REMAINING
RECOVERY
1997 1996 PERIOD*
(000) ---- ---- ---------
Recoverable Future Federal
Income Taxes...................................... $ 85,858 $ 85,858 (A)
Unrecovered Purchased Power Costs:
Capacity Cost..................................... 48,038 64,658 3 years
Contract Renegotiation Costs...................... 18,226 18,742 17 years
Unrecovered State Excise Taxes..................... 45,154 54,714 5 years
Unamortized Debt Costs-Refundings.................. 30,002 29,878 1-29 years
Deferred Energy Costs (See Note 1)................. 27,424 33,529 (B)
Other Regulatory Assets:
Postretirement Benefits Other Than Pensions (See
Notes 3&5)....................................... 37,476 32,609 15 years
Asbestos Removal Costs............................ 8,816 9,086 32 years
Decommissioning/Decontaminating Federally-owned
Nuclear Units
(See Note 11)..................................... 5,032 5,726 11 years
Other.............................................. 10,789 12,154
-------- --------
$316,815 $346,954
======== ========
- --------
* From December 31, 1997
(A) Pending future recovery
(B) Recovered over annual LEC period
Recoverable Future Federal Income Taxes is the amount of revenue expected to
be collected from ratepayers for deferred tax costs to be paid in future
years. Unrecovered Purchased Power Capacity Costs represent deferrals of prior
capacity costs then in excess of levelized revenues associated with a certain
long term capacity arrangement. Levelized revenues have since been greater
than costs, permitting the deferred costs to be amortized to expense. Contract
Renegotiation Costs were incurred through renegotiation of a long term
capacity and energy contract with a certain independent power producer.
Unrecovered State Excise Taxes represent additional amounts paid as a result
of prior legislative changes in the computation of state excise taxes.
Unamortized Debt Costs associated with debt reacquired by refundings are
amortized over the life of the related new debt. FASB Statement of Financial
Accounting Standard No. 106 -- "Employers Accounting for Post-retirement
Benefits Other Than Pensions" (SFAS 106) required companies to recognize an
obligation composed of the present value of OPEB obligations for retirees and
current employees incurred as of the date of adoption. In December 1992, ACE
adopted SFAS 106, applied deferred accounting to these OPEB costs and began to
record a regulatory asset consistent with SFAS 71. In December 1997, the BPU
approved an increase in annual base rate revenues of $5.0 million for recovery
of expenses associated with OPEB costs. This amount included recovery of the
regulatory asset over a 15 year period beginning in January 1998. Asbestos
Removal Costs were incurred to remove asbestos insulation from a wholly-owned
generating station. Included in Other are certain amounts being recovered over
a period of one to five years.
70
NOTE 14. LEASES
ACE leases from others 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:
1997 1996
(000) ---- ----
Production plant.......................................... $ 6,642 $ 6,642
Less accumulated amortization............................. 5,707 5,005
------- -------
Net....................................................... 935 1,637
Nuclear fuel.............................................. 38,795 38,277
------- -------
Leased property-net....................................... $39,730 $39,914
======= =======
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 1997,
1996 and 1995 include leased nuclear fuel costs of $9.8 million, $8.7 million
and $11.2 million, respectively, and rentals and lease payments for all other
capital and operating leases of $2.7 million, $2.6 million and $3.9 million,
respectively. Future minimum rental payments for all noncancellable lease
agreements are less than $2.5 million per year for each of the next 5 years.
ATE is the lessor in five leveraged lease transactions consisting of three
aircraft and two containerships with total respective costs of approximately
$168 million and $76 million. Remaining lease terms for all leases approximate
13 to 14 years. The Company's equity participation in the leases range from
22% to 32%. Funding of the investment in the leveraged lease transactions is
comprised of equity participation by ATE and financing provided by third
parties as long term debt without recourse to ATE. The lease transactions
provide collateral for such third parties, including a security interest in
the leased equipment.
Net investment in leveraged leases at December 31 was as follows:
1997 1996
(000) ---- ----
Rentals receivable (net of principal and interest on
nonrecourse debt)..................................... $50,841 $50,898
Estimated residual values.............................. 53,435 53,435
Unearned and deferred income........................... (23,828) (24,646)
------- -------
Investment in leveraged leases......................... 80,448 79,687
Deferred taxes arising from leveraged leases........... (76,362) (76,671)
------- -------
Net investment in leveraged leases..................... $ 4,086 $ 3,016
======= =======
NOTE 15. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company does not use derivative financial instruments in its investment
portfolio or for trading purposes. ACE and AEE are exposed to market changes
in certain energy commodity prices (natural gas and electricity). To minimize
the risk of market fluctuations associated with the purchase and sale of
energy commodities both ACE and Enerval enter into various transactions
involving derivative financial instruments for hedging purposes.
ACE enters into agreements to buy and sell electricity at a predetermined
price for future periods. ACE utilizes purchased and written options to
purchase or sell a predetermined amount of electricity at a predetermined
price in an effort to limit ACE's risk related to those agreements. Gains or
losses associated with derivative transactions are recognized in operations in
the period the derivative instrument is terminated or
71
extinguished or ceases to be qualified as a hedge. ACE has established risk
management policies and procedures to minimize the level of risk associated
with electric marketing transactions. At December 31, 1997, ACE's unhedged
outstanding commitments to sell energy were immaterial.
AEE through Enerval enters into fixed-priced contracts which commit the
company to sell, up to a predetermined volume, natural gas at a fixed price.
To meet the physical gas supply delivery requirements under these gas sales
contracts, Enerval enters into natural gas physical purchase contracts based
on market price. In order to hedge its price risk relative to its fixed price
sales commitments, Enerval utilizes natural gas futures contracts to reduce
its exposure relative to the volatility of market prices. Enerval records the
gain or loss resulting from changes in the market value of the futures
contract as an increase or decrease to fuel costs when the corresponding sale
is made.
As a service to Enerval, the other 50% owner enters into futures contracts
on Enerval's behalf. As of December 31, 1997, this owner entered into natural
gas futures contracts on behalf of Enerval for 9.3 million DTH at a price
range of $1.90 to $3.20, through March 2000 in the notional amount of $21.2
million. The original contract terms range from one month to two years.
Enerval's futures contracts hedge $21.7 million in anticipated natural gas
sales. The counterparties to the futures contracts are the New York Mercantile
Exchange and major over the counter market traders. The Company believes the
risk of nonperformance by these counterparties is not significant. If the
contracts had been terminated at December 31, 1997, $0.6 million would have
been payable by Enerval for the natural gas price fluctuations.
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 fixed 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.
ACE's long term debt and preferred securities and ATE's long term debt
securities are not widely held and generally trade infrequently. The estimated
aggregate fair value of debt securities has been determined based on quoted
market prices for the same or similar debt issues or on securities of
companies with similar credit quality, coupon rates and maturities. The
aggregate fair value of preferred securities has been determined using market
information available from actual trades or of trades of similar instruments
of companies with similar credit quality. At December 31 the amounts are as
follows:
LONG TERM DEBT AND PREFERRED SECURITIES
(IN MILLIONS)
1997 1996
---- ----
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- ----- -------- -----
ACE Long Term Debt......................... $833.7 $859.5 $802.4 $828.8
ACE Preferred Stock........................ 64.0 60.1 74.0 77.1
Preferred Securities*...................... 70.0 72.3 70.0 69.3
AEI Long Term Debt......................... 53.5 53.5 37.6 37.6
ATS Long Term Debt......................... 120.1 120.1 54.5 54.5
ATE Long Term Debt......................... 20.0 20.3 33.5 34.0
- --------
* ACE Obligated Mandatorily Redeemable Preferred Securities of Subsidiary
Trust Holding Solely Junior Subordinated Debentures of ACE
72
NOTE 16. QUARTERLY FINANCIAL RESULTS (UNAUDITED)
Quarterly financial data, reflecting all adjustments necessary in the
opinion of management for a fair presentation of such amounts, are as follows:
BASIC DILUTED DIVIDENDS
OPERATING OPERATING NET EARNINGS EARNINGS PAID
QUARTER REVENUES INCOME INCOME PER SHARE PER SHARE PER SHARE
- ------- --------- --------- ------ --------- --------- ---------
1997 (000) (000) (000)
1st................ $ 245,529 $ 47,172 $18,631 .35 $ .35 $.385
2nd................ 244,338 44,659 16,845 .32 .32 .385
3rd................ 340,623 89,456 46,466 .89 .88 .385
4th................ 271,870 7,916 (7,537) (.14) (.14) .385
---------- -------- ------- ----- ----- -----
Annual............. $1,102,360 $189,203 $74,405 $1.42 $1.42 $1.54
========== ======== ======= ===== ===== =====
1996
1st................ $ 246,911 $ 39,853 $15,535 .30 $ .30 $.385
2nd................ 228,321 32,476 10,250 .20 .20 .385
3rd................ 286,273 67,631 32,567 .62 .62 .385
4th................ 235,533 18,717 415 .01 .01 .385
---------- -------- ------- ----- ----- -----
Annual............. $ 997,038 $158,677 $58,767 $1.12 $1.12 $1.54
========== ======== ======= ===== ===== =====
Certain prior year amounts have been reclassified to conform to the current
year reporting of these items. The most notable reclassification, with no
effect on net income, pertains to the Company's nonutility activities
previously reported in the Other Income line on the Consolidated Statement of
Income. The revenues, operating expenses and income taxes from those
operations are now reflected on the appropriate line items.
Third quarter results generally exceed those of other quarters due to
increased sales and higher residential rates for ACE. Individual quarters may
not add to the total due to rounding.
The fourth quarter 1997 Net Income reflects a charge of $16.5 million, after
tax of $7.1 million recorded in December 1997 for the termination of various
pension and compensation plans in anticipation of the merger. (See Note 4. --
Merger). These expenses are included in operations expense and are classified
as Termination of Employee Benefit Plans on the consolidated income statement.
The fourth quarter 1996 Net Income reflects an increase in ACE's electric
sales offset in part by the increase in energy expense due to increased sales,
recovery of previously deferred energy costs and an increase in operations and
maintenance expense related to Salem. During the fourth quarter of 1996
nonutility operations recorded a $1.6 million net of tax loss contingency for
the sale of the Binghamton Cogeneration Facility by AGI, $0.8 million net of
tax write-down of the carrying value of ASP's commercial building and $1.1
million net of tax loss for AEE's investment in Enerval.
73
NOTE 17. SUBSEQUENT EVENTS (UNAUDITED)
Salem Unit 1 is presently expected to return to service during the second
quarter of 1998.
ACE will file its petition with the BPU during the second quarter of 1998
requesting an increase in 1998-1999 annual LEC revenues.
ACE submitted its second Demand Side Management (DSM) Plan for the period
from September 1997 through August 1998 in April 1997. The DSM Plan includes
programs which address energy conservation needs of the residential,
commercial and industrial markets but are not intended to promote new uses of
electricity. Motions were filed on behalf of interveners who were granted full
intervenor status by the BPU on July 30, 1997. During the course of the DSM
proceedings, the Ratepayer Advocate alledged that ACE has been recovering more
in rates for DSM purposes then it is spending. The interveners, the BPU (the
Parties) and ACE have come to an agreement on the terms of the Plan except
with regard to the overrecovery issue. On March 10, 1998, ACE filed a
reconciliation of its Demand Side Management programs with the BPU. The
purpose of this filing was to detail the level of DSM expenditures for the
calendar years 1994 through 1997. ACE's position is that the level of DSM
expenditures cannot be viewed in isolation, but must be considered in light of
both the overall history of DSM expenditures under current rates and the
overall revenue requirement needs in a rate proceeding. As of the date of this
filing responses from the Parties have not yet been received. Upon their
receipt the matter will then be submitted to the BPU for review. ACE is unable
to determine the probable outcome of this matter at this time.
74
REPORT OF MANAGEMENT-ATLANTIC CITY ELECTRIC COMPANY
The management of Atlantic City Electric Company and its subsidiary (the
Company) is responsible for the preparation of the consolidated financial
statements presented in this Annual Report. The financial statements have been
prepared in conformity with generally accepted accounting principles. In
preparing the consolidated financial statements, management made informed
judgments and estimates, as necessary, relating to events and transactions
reported.
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, 1997, 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 consolidated 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, 1997 represented
significant deficiencies in the design or operation of the Company's internal
control structure.
/s/ M. J. Chesser
By___________________________________
M. J. Chesser President and Chief
Operating Officer
/s/ M. J. Barron
By___________________________________
M. J. Barron Senior Vice President
and Chief Financial Officer
February 2, 1998
75
INDEPENDENT AUDITORS' REPORT
To Atlantic City Electric Company:
We have audited the accompanying consolidated balance sheets of Atlantic
City Electric Company and subsidiary as of December 31, 1997 and 1996 and the
related consolidated statements of income, changes in common shareholder's
equity, and cash flows for each of the three years in the period ended
December 31, 1997. 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 audits 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 City Electric
Company and subsidiary at December 31, 1997 and 1996 and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1997 in conformity with generally accepted accounting
principles.
/s/ Deloitte & Touche LLP
_____________________________________
Deloitte & Touche LLP
February 2, 1998 (March 1, 1998 as to Note 4)
Parsippany, New Jersey
76
[THIS PAGE INTENTIONALLY LEFT BLANK]
77
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(DOLLARS, IN THOUSANDS)
DECEMBER 31,
------------
1997 1996
---- ----
ASSETS
Electric Utility Plant
In Service:
Production.............. $1,242,049 $1,212,380
Transmission............ 383,577 373,358
Distribution............ 763,915 731,272
General................. 195,745 191,210
---------- ----------
Total In Service......... 2,585,286 2,508,220
Less Accumulated
Depreciation............ 934,235 871,531
---------- ----------
Utility Plant in Service-
Net..................... 1,651,051 1,636,689
Construction Work in
Progress................ 95,120 117,188
Land Held for Future
Use..................... 5,604 5,604
Leased Property-Net...... 39,730 39,914
---------- ----------
1,791,505 1,799,395
---------- ----------
Investments and
Nonutility Property
Nuclear Decommissioning
Trust Fund.............. 81,650 71,120
Other.................... 10,853 9,750
---------- ----------
92,503 80,870
---------- ----------
Current Assets
Cash and Temporary
Investments............. 5,640 7,927
Accounts Receivable:
Utility Service......... 64,511 64,432
Miscellaneous........... 23,507 21,650
Allowance for Doubtful
Accounts............... (3,500) (3,500)
Unbilled Revenues........ 36,915 33,315
Fuel (at average cost)... 29,159 29,603
Materials and Supplies
(at average cost)....... 20,893 23,815
Working Funds............ 15,125 15,517
Deferred Energy Costs.... 27,424 33,529
Prepaid Excise Tax....... 3,804 7,125
Other Prepayments........ 16,273 10,089
---------- ----------
239,751 243,502
---------- ----------
Deferred Debits
Unrecovered Purchased
Power Costs............. 66,264 83,400
Recoverable Future
Federal Income Taxes.... 85,858 85,858
Unrecovered State Excise
Taxes................... 45,154 54,714
Unamortized Debt Costs... 43,418 43,579
Deferred Other Post
Retirement Employee
Benefit Costs........... 37,476 32,609
Other Regulatory Assets.. 24,637 26,966
Other.................... 10,189 9,848
---------- ----------
312,996 336,974
---------- ----------
Total Assets............. $2,436,755 $2,460,741
========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
78
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(DOLLARS, IN THOUSANDS)
DECEMBER 31,
------------
1997 1996
---- ----
LIABILITIES AND CAPITALIZATION
Capitalization
Common Shareholder's Equity:
Common Stock........................................... $ 54,963 $ 54,963
Premium on Capital Stock............................... 231,081 231,081
Contributed Capital.................................... 263,617 259,078
Capital Stock Expense.................................. (1,537) (1,645)
Retained Earnings...................................... 234,909 234,948
---------- ----------
Total Common Shareholder's Equity...................... 783,033 778,425
---------- ----------
Preferred Securities:
Not Subject to Mandatory Redemption................... 30,000 30,000
Subject to Mandatory Redemption....................... 33,950 43,950
Company-Obligated Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of the Company............... 70,000 70,000
Long Term Debt........................................ 833,744 802,245
---------- ----------
1,750,727 1,724,620
---------- ----------
Current Liabilities
Preferred Stock Redemption Requirement................. -- 10,000
Capital Lease Obligations-Current...................... 653 702
Long Term Debt-Current................................. -- 175
Short Term Debt........................................ 55,675 64,950
Accounts Payable....................................... 56,672 63,644
Federal Income Taxes Payable-Affiliate................. -- 7,398
Other Taxes Accrued.................................... 5,922 7,494
Interest Accrued....................................... 19,562 19,619
Dividends Declared..................................... 21,215 21,701
Deferred Income Taxes.................................. 1,888 3,190
Provision for Rate Refunds............................. -- 13,000
Other.................................................. 20,293 19,137
---------- ----------
181,880 231,010
---------- ----------
Deferred Credits and Other Liabilities
Deferred Income Taxes.................................. 362,213 357,580
Deferred Investment Tax Credits........................ 44,043 46,577
Capital Lease Obligations.............................. 39,077 39,212
Accrued Other Post Retirement Employee Benefit Costs... 37,476 32,609
Other.................................................. 21,339 29,133
---------- ----------
504,148 505,111
---------- ----------
Commitments and Contingencies (Note 11)
Total Liabilities and Capitalization................... $2,436,755 $2,460,741
========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
79
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(DOLLARS, IN THOUSANDS)
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
---- ---- ----
Operating Revenues
Electric................................ $ 1,068,534 $ 984,360 $ 953,779
Other Services.......................... 16,356 5,287 1,004
------------ ---------- ----------
1,084,890 989,647 954,783
------------ ---------- ----------
Operating Expenses
Energy.................................. 293,457 225,185 191,766
Purchased Capacity...................... 197,386 195,699 190,570
Operations.............................. 154,556 163,633 153,397
Maintenance............................. 32,634 44,462 34,414
Termination of Employee Benefit Plans... 22,246 -- --
Depreciation and Amortization........... 83,276 80,845 78,461
State Excise Taxes...................... 103,991 104,815 102,811
Taxes Other Than Income................. 7,292 9,888 8,677
------------ ---------- ----------
894,838 824,527 760,096
------------ ---------- ----------
Operating Income........................ 190,052 165,120 194,687
------------ ---------- ----------
Other Income
Allowance for Equity Funds Used During
Construction........................... 815 879 817
Other-Net............................... 14,595 11,275 12,725
------------ ---------- ----------
15,410 12,154 13,542
------------ ---------- ----------
Interest Charges
Interest Expense........................ 64,501 64,847 62,879
Allowance for Borrowed Funds Used During
Construction........................... (1,003) (976) (1,679)
------------ ---------- ----------
63,498 63,871 61,200
------------ ---------- ----------
Less Preferred Securities Dividend of
Trust.................................. 5,775 1,428 --
------------ ---------- ----------
Income Before Income Taxes.............. 136,189 111,975 147,029
Federal Income Taxes.................... 50,442 36,958 48,277
------------ ---------- ----------
Net Income.............................. 85,747 75,017 98,752
Less Preferred Stock Dividend
Requirements........................... 4,821 9,904 14,627
------------ ---------- ----------
Income Available for Common Stock....... $ 80,926 $ 65,113 $ 84,125
============ ========== ==========
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
80
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(DOLLARS, IN THOUSANDS)
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1997 1996 1995
---- ---- ----
Cash Flows of Operating Activities
Net Income................................. $ 85,747 $ 75,017 $ 98,752
Unrecovered Purchased Power Costs.......... 17,136 16,417 15,721
Deferred Energy Costs...................... 6,105 (2,095) (20,435)
Preferred Securities Dividends of Trust.... 5,775 1,428 --
Depreciation and Amortization.............. 83,276 80,845 78,461
Deferred Income Taxes-Net.................. 796 1,448 15,694
Unrecovered State Excise Taxes............. 9,560 9,560 9,560
Changes-Net Working Capital Components:
Accounts Receivable and Unbilled
Revenues................................. (5,536) 5,795 (22,565)
Accounts Payable & Federal Income Taxes
Payable-Affiliate........................ (14,370) 2,814 (4,801)
Inventory................................. 3,365 (2,523) 4,960
Other..................................... (6,532) 6 (9,838)
Rate Refunds............................... (13,000) 13,000 --
Employee Separation Costs.................. (308) (7,179) (19,112)
Other-Net.................................. (1,744) 18,139 11,266
--------- ---------- -----------
Net Cash Provided by Operating Activities.. 170,270 212,672 157,663
--------- ---------- -----------
Cash Flows of Investing Activities
Construction Expenditures.................. (80,849) (86,805) (100,904)
Leased Nuclear Fuel Material............... (9,105) (6,833) (10,446)
Plant Removal Costs........................ (47) (2,109) (4,525)
Other-Net.................................. (3,508) (15,707) 892
--------- ---------- -----------
Net Cash Used by Investing Activities...... (93,509) (111,454) (114,983)
--------- ---------- -----------
Cash Flows of Financing Activities
Issuance of Preferred Securities........... -- 70,000 --
Proceeds from Long Term Debt............... 87,600 -- 104,404
Retirement and Maturity of Long Term Debt.. (74,066) (12,266) (57,489)
Increase in Short Term Debt................ 7,150 34,405 21,945
Proceeds from Nuclear Fuel Capital Lease
Obligations............................... 9,105 6,833 10,446
Redemption of Preferred Stock.............. (20,000) (98,876) (24,500)
Capital Stock Dividends Declared........... (85,678) (92,066) (95,866)
Preferred Securities of Trust.............. (5,775) (1,428) --
Capital Contributions from Parent (net).... 4,539 (567) (223)
Other-Net.................................. (1,923) (3,313) (869)
--------- ---------- -----------
Net Cash Used by Financing Activities...... (79,048) (97,278) (42,152)
--------- ---------- -----------
Net Increase in Cash and Temporary
Investments............................... (2,287) 3,940 528
Cash and Temporary Investments:
Beginning of Year......................... 7,927 3,987 3,459
--------- ---------- -----------
End of Year............................... $ 5,640 $ 7,927 $ 3,987
========= ========== ===========
Supplemental Schedule of Payments:
Interest................................... $ 64,966 $ 65,269 $ 58,274
Federal Income Taxes....................... $ 48,400 $ 36,937 $ 31,999
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
81
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDER'S EQUITY (DOLLARS, IN
THOUSANDS)
PREMIUM CAPITAL
COMMON ON CAPITAL CONTRIB. STOCK RETAINED
STOCK STOCK CAPITAL EXPENSE EARNINGS
------ ---------- -------- ------- --------
Balance, December 31, 1994.... $54,963 $231,081 $259,868 $(2,300) $249,767
Net Income.................... 98,752
Capital Stock Expense......... 169 (169)
Capital Contrib. from Parent
(net)........................ (223)
Less Dividends Declared:
Preferred.................... (14,627)
Common....................... (81,239)
------- -------- -------- ------- --------
Balance, December 31, 1995.... 54,963 231,081 259,645 (2,131) 252,484
Net Income.................... 75,017
Capital Stock Expense......... 486 (486)
Capital Contrib. from Parent
(net)........................ (567)
Less Dividends Declared:
Preferred.................... (9,904)
Common....................... (82,163)
------- -------- -------- ------- --------
Balance, December 31, 1996.... 54,963 231,081 259,078 (1,645) 234,948
Net Income.................... 85,747
Capital Stock Expense......... 108 (108)
Capital Contrib. from Parent
(net)........................ 4,539
Less Dividends Declared:
Preferred.................... (4,821)
Common....................... (80,857)
------- -------- -------- ------- --------
Balance, December 31, 1997.... $54,963 $231,081 $263,617 $(1,537) $234,909
======= ======== ======== ======= ========
- --------
As of December 31, 1997, the Company had 25 million authorized shares of
Common Stock at $3 par value. Shares outstanding at December 31, 1997, 1996 and
1995 were 18,320,937.
The accompanying Notes to Consolidated Financial Statements are an integral
part of these statements.
82
ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Except as modified below, Notes 1 through 17, excluding Note 7 and Note 10,
to the Consolidated Financial Statements of Atlantic Energy Inc. (AEI) are
incorporated herein by reference insofar as they relate to Atlantic City
Electric Company (ACE) and its subsidiary:
NOTE 1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements include the accounts of ACE and
Deepwater Operating Company (Deepwater) its wholly-owned subsidiary. On
January 1, 1998, Deepwater was merged into ACE with no financial effect on
financial position or results of operations of ACE. All significant
intercompany accounts and transactions have been eliminated in consolidation.
Reclassification
Certain prior year amounts have been reclassified to conform to the current
year reporting of these items. The most notable reclassification, with no
effect on net income, pertains to the Company's nonutility activities
previously reported in the Other Income line on the Consolidated Statement of
Income. The revenues, operating expenses and income taxes from those
operations are now reflected on the appropriate line items.
Related Party Transactions
ACE has a contract for a total of 116 megawatts of capacity and related
energy from a cogeneration facility that is 50% owned by a wholly-owned
subsidiary of Atlantic Energy Enterprises, Inc. (AEE). Capacity costs totaled
$28.6 million in 1997, $27.8 million in 1996 and $23.8 million in 1995. ACE
sells electricity to subsidiaries of AEE. The electric sales totaled $6.5
million for 1997, $2.2 million for 1996 and $0.6 million for 1995. ACE also
rents office space from a wholly-owned subsidiary of AEE which amounts are not
significant. The amounts receivable from and payable to affiliates were not
significant at December 31, 1997 and 1996.
NOTE 2. INCOME TAXES
The components of Federal income tax expense for the years ended December 31
are as follows:
1997 1996 1995
(000) ---- ---- ----
Current........................................... $49,646 $35,510 $32,457
Deferred.......................................... 796 1,448 15,820
------- ------- -------
Total Federal Income Tax Expense.................. $50,442 $36,958 $48,277
======= ======= =======
A reconciliation of the expected Federal income taxes compared to the
reported Federal income tax expense computed by applying the statutory rate
for the years ended December 31 follows:
1997 1996 1995
(000) ---- ---- ----
Statutory Federal Income
Tax Rate............... 35 % 35 % 35 %
Income Tax Computed at
the Statutory Rate..... $47,666 $39,191 $51,417
Plant Basis
Differences............ 4,952 3,096 1,307
Amortization of
Investment Tax
Credits................ (2,534) (2,534) (2,534)
Other -- Net............ 358 (2,795) (1,913)
------- ------- -------
Total Federal Income Tax
Expense................ $50,442 $36,958 $48,277
======= ======= =======
Effective Federal Income
Tax Rate............... 37 % 33 % 33 %
The increase in the effective Federal income tax expense rate is due
primarily to permanently non-deductible merger and merger related expenses.
State income tax expense is not significant.
83
Items comprising deferred tax balances as of December 31 are as follows:
1997 1996
(000) ---- ----
Deferred Tax Liabilities:
Plant Basis Differences................................. $332,288 $326,673
Unrecovered Purchased Power Costs....................... 16,813 22,630
State Excise Taxes...................................... 16,326 20,141
Other................................................... 34,190 29,344
-------- --------
Total Deferred Tax Liabilities.......................... 399,617 398,788
-------- --------
Deferred Tax Assets:
Deferred Investment Tax Credits......................... 23,775 25,143
Other................................................... 11,741 12,875
-------- --------
Total Deferred Tax Assets............................... 35,516 38,018
-------- --------
Total Deferred Taxes -- Net............................. $364,101 $360,770
======== ========
On July 14, 1997 the Governor signed a bill into law eliminating the Gross
Receipts and Franchise Tax (GR & FT) paid by the electric, natural gas and
telecommunication public utilities. In its place, utilities will be subject to
the state's corporate business tax. In addition, the state's existing sales
and use tax will be expanded to include retail sales of electric power and
natural gas, and a transitional energy facility assessment tax (TEFA) will be
applied for a limited time on electric and natural gas utilities and will be
phased-out over a five year period. The law took effect January 1, 1998 and on
January 1 of each of the years thereafter, the TEFA will be reduced by 20%. By
the year 2003, the TEFA will be fully phased-out and the savings will be
passed through to ACE's Customers. As a result of this law, ACE will record
deferred state taxes beginning in 1998 for state tax basis versus book basis
differences.
NOTE 16. QUARTERLY FINANCIAL RESULTS (UNAUDITED).
Quarterly financial data of ACE, reflecting all adjustments necessary in the
opinion of management for a fair presentation of such amounts, are as follows:
OPERATING OPERATING NET EARNINGS FOR
QUARTER REVENUES INCOME INCOME COMMON STOCK
------- --------- --------- ------ ------------
(000) (000) (000) (000)
1997
1st............................. $ 243,443 $ 47,350 $20,371 $18,961
2nd............................. 242,567 45,028 18,676 17,266
3rd............................. 338,070 89,123 47,541 46,541
4th............................. 260,810 8,551 (841) (1,842)
---------- -------- ------- -------
Annual.......................... $1,084,890 $190,052 $85,747 $80,926
========== ======== ======= =======
1996
1st............................. $ 245,656 $ 40,716 $19,316 $16,307
2nd............................. 226,858 33,658 13,464 10,455
3rd............................. 284,506 68,766 35,611 33,154
4th............................. 232,627 21,980 6,627 5,197
---------- -------- ------- -------
Annual.......................... $ 989,647 $165,120 $75,017 $65,113
========== ======== ======= =======
Individual quarters may not add to the total due to rounding.
84
Certain prior year amounts have been reclassified to conform to the current
year reporting of these items. The most notable reclassification, with no
effect on net income, pertains to the Company's nonutility activities
previously reported in the Other Income line on the Consolidated Statement of
Income. The revenues, operating expenses and income taxes from those
operations are now reflected on the appropriate line items.
Third quarter results generally exceed those of other quarters due to
increased sales and higher residential rates for ACE.
The fourth quarter 1997 Net Income reflects a charge of $15.6 million, after
tax of $6.6 million recorded in December 1997 for the termination of various
pension and compensation plans in anticipation of the merger. (See AEI Note
4. -- Merger). These expenses are included in operations expense and are
classified as Termination of Employee Benefit Plans on the consolidated income
statement.
The fourth quarter 1996 Net Income reflects an increase in ACE's electric
sales offset in part by the increase in energy expense due to the increased
sales, recovery of previously deferred energy costs and an increase in
operations and maintenance expense related to Salem.
85
ITEM 9 CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
PART III
ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS OF THE COMPANY
As of December 31, 1997
Gerald A. Hale............. President of Hale Resources, Inc., Summit, NJ,
a health care, industrial/natural resource
investment and management company. General
Manager of HHH Investment Company, LLC.
Director of New Jersey Manufacturers Insurance
Company, New Jersey Business and Industry
Association and Hoke, Inc. Director of the
Company since 1983.
Matthew Holden, Jr. ....... Professor of Government & Foreign Affairs,
University of Virginia, Charlottesville, VA.
Economic and political consultant, arbitrator.
Prior to 1982, Commissioner, Federal Energy
Regulatory Commission and Wisconsin Public
Service Commission. Director of the Company
since 1981.
Cyrus H. Holley............ President of Management Consulting Services,
Grapevine, TX. Director and Chief Executive
Officer of Oakmont Enterprises, Grapevine, TX.
Director of UGI Corporation and Kerns Oil &
Gas Company. Director of the Company since
1990.
Jerrold L. Jacobs.......... Chairman of the Board and Chief Executive
Officer of Atlantic Energy and Chairman and
Atlantic City Electric Company. Formerly
President of Atlantic Energy. Director of the
Company since 1990.
Kathleen MacDonnell........ Former Corporate Vice President of Campbell
Soup Company, Camden, NJ. President, Frozen
Foods & Specialty Group, of Campbell Soup
Company. Former Sector Vice President,
Prepared Foods, and Sector Vice President,
Grocery, of Campbell Soup Company. Director of
the Company since 1993.
Richard B. McGlynn......... Attorney. Vice President and General Counsel
of United Water Resources, Inc., Harrington
Park, NJ. Former Partner in the law firm of
LeBoeuf, Lamb, Greene & MacRae and Former
Partner in the law firm of Stryker, Tams &
Dill. Director of the Company since 1986.
Bernard J. Morgan.......... Financial Investor, Southampton, PA. Director
of FormMaker Software, Inc., Atlanta, GA.
Former Vice Chairman of First Fidelity
Bancorporation, NJ/PA, Former Vice Chairman,
President, Chief Executive Officer and Chief
Operating Officer of Fidelcor, Inc. Former
Chairman, Deputy Chairman, Chief Executive
Officer, President and Chief Operating Officer
of Fidelity Bank, N.A. Director of the Company
since 1988.
86
Harold J. Raveche.......... President of Stevens Institute of Technology,
Hoboken, NJ., Chair of the Board of the New
Jersey Corporation for Advanced Technology.
Former Dean of Science, Rensselaer Polytechnic
Institute. Director of the Company since 1990.
EXECUTIVE OFFICERS
Information concerning the Executive Officers of the Company and ACE, as of
December 31, 1997, 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 (58).. Chairman and Chief Executive Officer of the
Company (7/1/96) and Chairman and Chief
Executive Officer of ACE (4/27/96).
Michael J. Chesser President and Chief Operating Officer of the
(49)................... Company (7/1/96) and President and Chief
Operating Officer of ACE (4/27/95). Director of
ACE.
Michael J. Barron (48).. Senior Vice President and Chief Financial
Officer of the Company (8/14/97) and Senior Vice
President and Chief Financial Officer of ACE
(9/15/95). Director of ACE.
Frank E. DiCola (50).... Vice President, Thermal Systems & Enerval
(10/10/96).
Robert H. Fiedler (51).. Acting Vice President -- Distribution of ACE
(10/10/96).
James E. Franklin II Vice President, Secretary and General Counsel to
(51)................... the Company (4//26/95)and Senior Vice President,
Secretary and General Counsel of ACE (4/27/95).
Director of ACE.
Meredith I. Harlacher, Vice President -- Power System of the
Jr. (55)............... Company (4/26/95) and Senior Vice President --
Power System of ACE (4/3/95), Director of ACE.
Ernest L. Jolly (45).... Vice President -- Energy Supply for the Company
and Senior Vice President -- Energy Supply of
ACE (12/1/97).
Henry K. Levari, Jr. Vice President -- External Affairs of the
(49)................... Company and Senior Vice President -- External
Affairs of ACE (11/13/95), Director of ACE.
J. David McCann (46).... Vice President -- Strategic Customer Support of
ACE (4/27/94).
Marilyn T. Powell (50).. Vice President Marketing/Distribution of the
Company and Senior Vice President --
Marketing/Distribution of ACE (10/10/96).
Director of ACE.
Louis M. Walters (45)... Treasurer of the Company (4/26/95) and Vice
President --Treasurer and Assistant Secretary of
ACE (1/31/95).
87
Prior to election to the positions above, the following officers held other
positions with the Company and ACE (unless otherwise noted) since January 1,
1992:
J.L. Jacobs................. Chairman and Chief Executive Officer of ACE
4/26/95); President and Chief Executive Officer
of the Company (4/27/94); Chairman, President
and Chief Executive officer of ACE (4/28/93).
M.J. Chesser................ Senior Vice President of the Company (4/26/95);
President and Chief Operating Officer of ACE
(4/27/95); Vice President of the Company
(2/1/94); Executive Vice President and Chief
Operating Officer of ACE (2/1/94); Vice
President -- Marketing & Gas Operations,
Baltimore Gas & Electric Company
M.J. Barron................. Vice President and Treasurer of Maxus Energy
Corporation, Dallas, Texas.
J.E. Franklin II............ Secretary and General Counsel to the Company and
ACE (2/1/95); 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 --Energy Supply of ACE (4/28/93);
Senior Vice President --Utility Operations of
ACE (8/9/91).
R. H. Fiedler............... General Manager Customer Operations of ACE
(3/13/95); Manager Ocean Region of ACE
(11/1/93); Manager Customer Service &
Information of ACE (1/4/93); General Manager
Administration of ACE (9/7/92)
E.L. Jolly.................. Vice President -- Human Resources and
Transformation of the Company and ACE (1/8/96);
Vice President --Atlantic Transformation of ACE
(5/23/94); Vice President --External Affairs of
ACE (3/1/92).
H.K. Levari, Jr............. Senior Vice President -- Planning and External
Affairs of ACE (4/3/95); Vice President --
Planning & External Affairs of the Company
(4/26/95); Vice President of the Company
(4/27/94); Senior Vice President -- Customer
Operations of ACE (9/16/94); Senior Vice
President --Marketing & Customer Operations of
ACE (4/28/93). Senior Vice President -- Planning
and Services of ACE (8/9/91).
J. D. McCann................ Vice President -- Power Delivery of ACE
(8/9/91).
M.T. Powell................. Vice President -- Marketing of the Company and
Senior Vice President -- Marketing of ACE
(11/9/95); Vice President -- Marketing of ACE
(9/16/94); Director of marketing process,
International Business Machines Corporation.
S.B. Ungerer................ Vice President -- Enterprise Activities of the
Company (4/26/95); Vice President of the Company
(1/17/94); Manager, Business Planning Services
(1/4/93); Manager, Strategic Business Planning
(1/6/92).
88
L.M. Walters................ Treasurer and Acting Chief Financial Officer
4/26/95); Vice President -- Treasurer and
Secretary (4/28/94); Vice President -- Treasurer
and Assistant Secretary (4/28/93); General
Manager, Treasury and Finance (8/9/91).
ITEM 11 EXECUTIVE COMPENSATION
DIRECTOR AND OFFICER COMPENSATION
As previously reported, the Company and Delmarva Power & Light Company
entered into an agreement to merge the companies (the "Merger") into a new
company named Conectiv, Inc. The merger and formation of Conectiv became
effective March 1, 1998 resulting in a change of control as defined in certain
compensation plans for Directors and Officers of the Company. In anticipation
and in preparation for this change of control, the Board of Directors of the
Company took action, as further described below, with respect to those
compensation plans.
DIRECTOR COMPENSATION
1997 COMPENSATION
During 1997, non-employee Directors received fees in accordance with the
following compensation schedule:
Retainer Fee.................................. $20,000 Annually
Board Meeting Fee............................. $ 1,000 Per Meeting Attended
Committee Meeting Fee* (if held same day as
Board meeting)............................... $ 1,150 Per Meeting Attended
Committee Meeting Fee* (if held other than
Board meeting date).......................... $ 1,150 Per Meeting Attended
Committee or Board Meeting Fee via Telephone.. $ 150 Per Conference
- --------
* Paid to committee members only.
Actual receipt of such amounts may be deferred, with interest, until a time
selected by the non-employee Director.
Three non-employee Directors were Directors of Atlantic Energy Enterprises,
Inc. ("AEE"), a holding company formed to own the shares of capital stock of
all of the Company's nonutility subsidiaries. Those directors received a per
meeting fee of $1,000 for attendance at meetings of the Board of Directors of
AEE.
DIRECTOR RETIREMENT PLAN
The Company had a retirement plan for non-employee Directors ("Director
Retirement Plan"). Under the Director Retirement Plan each non-employee
Director who had five years of service was eligible to receive benefits for
the longer of life or the full number of years the non-employee Director
served on the Board. Non-employee Directors who satisfied the service
requirement would receive an annual benefit starting in the year they
terminated service. The Director Retirement Plan provided that in the event of
a change of control of the Company, as took place as a result of the Merger,
any non-employee Director having less than five years of service would be
deemed to have served for five years to satisfy the service requirement; and
in such event for all Directors, the net present value of the annual benefit
would be calculated in accordance with the terms of the Director Retirement
Plan and payable in a lump sum. On November 13, 1997 the Board of Directors of
the Company, exercising the authority granted to them under the provisions of
the Director Retirement Plan, terminated the Director Retirement Plan
effective at the effective time of the Merger.
89
RESTRICTED STOCK PLANS
Shares of restricted stock were granted to non-employee Directors to enhance
recruitment and retention of highly qualified individuals and to strengthen
the commonality of interests between non-employee Directors and shareholders.
The Director Restricted Plan (the "DRSP") was established in 1991 and
terminated in 1994. All non-employee directors, serving as of December 31,
1997, had received a one-time grant of 2,000 shares, subject to certain
restrictions. In anticipation of the consummation of the Merger, the Board of
Directors of the Company, on November 13, 1997, exercising the authority
granted to them under the provisions of the DRSP, terminated the Plan
effective at the effective time of the Merger. At that time, all shares not
previously vested, became fully vested and were distributed to each Director.
Under an Equity Incentive Plan ("EIP"), approved by shareholders in 1994,
each non-employee Director would receive a grant of 1,000 shares every five
years, subject to certain restrictions. Grants under the EIP commenced in the
year following a non-employee Director's full vesting in grants previously
received by each non-employee Director under the DRSP. Two non-employee
Directors had received a grant under the EIP of 1,000 shares subject to
restriction.
Under the terms of the EIP, in the event of a change of control, including
as took place as a result of the Merger, the restrictions applicable to any
restricted stock would lapse and such shares were deemed fully vested. In
anticipation of the consummation of the Merger, the Board of Directors of the
Company, on November 13, 1997, exercising the authority granted to them under
the provisions of the EIP, terminated the Plan effective December 31, 1997 and
the shares were distributed to the two non-employee Directors. The stock
ownership reported for each non-employee Director includes shares granted to
them under the EIP and DRSP.
90
EXECUTIVE COMPENSATION
The following table provides certain summary information concerning
compensation of the Company's Chief Executive Officer and the four other most
highly compensated executive officers as of December 31, 1997.
TABLE 1 -- SUMMARY COMPENSATION TABLE
LONG-TERM COMPENSATION
----------------------
ANNUAL COMPENSATION AWARDS PAYOUTS
------------------- ------ -------
OTHER SECURITIES
NAME AND ANNUAL RESTRICTED UNDERLYING LTIP ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION (1) STOCK ($) OPTIONS (#) PAYOUTS COMPENSATION (2)
------------------ ---- ------ ----- ---------------- ---------- ----------- ------- ----------------
J. L. Jacobs 1997 $472,917 $306,400 $1,806,787 -- -- -- $8,324,628
Chairman and Chief 1996 449,167 23,600 $13,461 $743,531 38,500 $14,388 16,439
Executive Officer of the 1995 435,000 -- 25,528 -- -- -- 13,050
Company and ACE
M.J. Chesser 1997 312,833 202,600 911,972 -- -- -- 1,931,544
President and Chief 1996 284,500 17,000 2,777 380,456 19,700 9,714 8,785
Operating Officer of the 1995 262,000 -- 7,039 -- -- -- 7,240
Company, ACE and AEE
M.I. Harlacher, Jr. 1997 224,525 96,800 814,696 -- -- -- 3,208,196
Vice President, Power 1996 215,317 27,500 8,527 305,138 15,800 10,429 7,413
System of the Company 1995 205,133 -- 10,070 -- -- -- 6,154
and Senior Vice
President, Power System
of ACE
M. T. Powell 1997 212,333 91,600 650,636 -- -- 1,684,311
Vice President, 1996 193,050 7,500 23,248 305,138 15,800 -- 6,282
Marketing/Distribution 1995 173,856 22,000 60,995 -- -- -- 5,216
of the Company and
Senior Vice President,
Marketing/Distribution
of ACE
M. J. Barron 1997 209,167 90,300 481,559 -- -- -- 1,428,809
Vice President, and 1996 199,333 67,600 -- 305,138 15,800 -- 6,373
Chief Financial Officer 1995 40,381 20,000 30,483 134,925 6,387 -- 564
of the Company and
Senior Vice President
and Chief Financial
Officer of ACE
- --------
(1) "Other Annual Compensation" includes tax reimbursement payments.
(2) "All Other Compensation" includes contributions by the Company in 1997
under the Atlantic Electric 401(k) Savings and Investment Plan-A ("401(k)
Plan"), a defined contribution plan; a matching contribution made pursuant
to the Company's Deferred Compensation Plan for Employees ("DCP"), a non-
qualified deferred compensation plan; premiums paid for the funding of
life insurance benefits under certain Company supplemental executive
retirement plans ("SERP").
The SERP plans provided for immediate vesting in the event of a change of
control, as took place as a result of the Merger, and these amounts are also
included in this column. In addition, pursuant to the change of control
provisions of the Company's equity based long term incentive plan for
executives ("EIP"), participants in the plan, including the executives named
in the Summary Compensation Table were given the option of receiving common
stock of the Company which had been awarded them under the plan, free of the
restrictions placed on the stock at the time of the award, or a cash
equivalent based on of change in control price set by the
91
Company's Board of Directors. The cash equivalent of the stock is reflected in
this column. Stock options which were also awarded under these plans were also
cashed out at a price set by the Company's Board of Directors and those
amounts are included in this column as well.
An adjustment to benefits was received by Messrs. Jacobs and Harlacher to
compensate them for certain economic disadvantages associated with the payout
of their benefits in 1997 rather than in 1998 and those amounts are also
included in this column. The following table details the components of this
column.
J. L. JACOBS M.J. CHESSER M. I. HARLACHER, JR. M.T. POWELL M.J. BARRON
------------ ------------ -------------------- ----------- -----------
401(k) Contributions.... $ 4,750 $ 4,750 $ 4,750 $ 4,750 $ 4,750
DCP Contributions....... 9,458 4,635 1,986 1,620 1,525
Insurance Premiums...... 3,141 1,292 1,065 839 747
SERP Payouts............ 2,192,799 1,065,693 996,238 760,354 562,653
EIP Payouts............. 1,739,044 460,335 674,340 674,340 674,340
Excess Retirement
Payouts................ 3,950,436 394,839 1,358,817 242,408 184,794
Benefits Adjustment..... 425,000 -- 171,000 -- --
---------- ---------- ---------- ---------- ----------
$8,324,628 $1,931,544 $3,208,196 $1,684,311 $1,428,809
========== ========== ========== ========== ==========
92
LOGO
COMPARISON OF FIVE YEAR CUMULATIVE TOTAL RETURN*
AMONG ATLANTIC ENERGY, INC., THE S & P 500 INDEX AND A PEER GROUP
*$100 INVESTED ON 12/31/92 IN STOCK OR INDEX-INCLUDING REINVESTMENT OF
DIVIDENDS. FISCAL YEAR ENDING DECEMBER 31.
12/31/92 12/31/93 12/31/94 12/31/95 12/31/96 12/31/97
Atlantic Energy Inc NJ ATE 100 100 89 105 102 137
PEER GROUP 100 110 94 130 130 173
S&P 500 100 110 112 153 189 252
The above graph compares the performance of Atlantic Energy, Inc. with that
of the S&P 500 Index and a peer group of utility companies with the investment
weighted based on market capitalization. The peer group is comprised of the
following companies:
Boston Edison Company, Central Hudson Gas & Electric Corporation, Central
Maine Power Company, Commonwealth Energy System, Delmarva Power & Light Co.,
DPL Inc., DQE Inc., New York State Electric & Gas Corporation, Orange &
Rockland Utilities, Incorporated, Potomac Electric Power Company, Rochester
Gas & Electric Corp., SCANA Corporation, UGI Corporation and United
Illuminating Company.
93
EMPLOYMENT AGREEMENTS
In 1995, the Company entered into employment agreements with certain
executive officers including those listed in the Summary Compensation Table on
page 91. The agreements provide for an initial two-year Employment Period that
may be automatically renewed for two years. Under the terms of the agreements
each executive officer is entitled to receive 1) a base salary, 2) incentive
compensation at the discretion of the Board of Directors based upon the
recommendation of the Committee, and 3) any other benefits that are available
from time to time to officers of the Company through the Employment Period.
The agreements also provide that if the employment of the executive officer is
terminated by the Company (or, under certain circumstances, by the executive
officer) following a change of control of the Company, as took place as a
result of the Merger, the executive officer will receive (a) the executive
officer's full base salary through the date of termination, (b) a cash amount
from the Company equal to three times the sum of (x) the executive officer's
annual base salary and (y) the higher of the bonus paid to the executive for
the most recent fiscal year or the target bonus for the current fiscal year
(the "Minimum Bonus Amount"), (c) the prorated portion of the executive
officer's unpaid Minimum Bonus Amount, (d) any other amounts otherwise payable
with respect to the Company's otherwise applicable long-term incentive
compensation and equity plans and programs, and (e) all vested amounts or
benefits owing to the executive officer under the Company's otherwise
applicable employee benefit plans and programs. In addition, the executive
officer will be entitled to continue to participate in the Company's employee
and executive pension, welfare and fringe benefit plans excluding supplemental
retirement benefits. For purposes of calculating the executive officer's
retirement benefit, three years will be added to both the executive officer's
age and service with the Company. The agreements further provide that if the
payments described above constitute "excess parachute payments" under
applicable provisions of the Internal Revenue Code and related regulations,
the Company will pay the executive officer an additional amount sufficient to
place the executive in the same after-tax financial position the executive
would have been in if the executive had not incurred the excise tax imposed
under Section 4999 of the Internal Revenue Code with respect to excess
parachute payments. As a result of the Merger, four of the executive officers
listed in the Summary Compensation Table on page 91 have terminated their
contracts and received the remaining benefits, not listed in Summary
Compensation Table, immediately following the consummation of the Merger on
March 1, 1998.
QUALIFIED AND EXCESS BENEFIT PLANS
The following table describes the estimated annual retirement benefit
payable under the Retirement Plan that is qualified under Section 401(a) of
the Internal Revenue Code ("Qualified Plan"). The Internal Revenue Code places
certain limitations on the amount of pension benefits that may be paid under
the Qualified Plan. Any benefits payable in excess of those limitations were
payable under an Excess Plan to certain eligible employees, including the
executive officers named in Summary Compensation Table, on page 91. The Excess
Plan provided for immediate vesting of benefits in the event of a change of
control of the Company, as took place as a result of the Merger and the amount
of those benefits are included in the Summary Compensation Table, on page 91.
The estimated retirement benefits paid to an employee assume a straight life
annuity to the employee, retirement at age 65, the average of the highest
earnings in five of the ten years preceding retirement and years of service
specified.
The credited full years of service at December 31, 1997 under the Retirement
Plan are as follows for the individuals named in the Summary Compensation
Table: Mr. Jacobs -- 36 years; Mr. Chesser -- 4 years, Mr. Barron -- 2 year,
Mr. Harlacher -- 32 years and Ms. Powell -- 3 years.
94
TABLE 5 -- PENSION PLAN TABLE
YEARS OF SERVICE
----------------
REMUNERATION 25 30 35 40 45
------------ -- -- -- -- --
$130,000 $ 52,000 $ 62,000 $ 73,000 $ 83,000 $ 94,000
190,000 76,000 91,000 106,000 122,000 130,000
250,000 100,000 120,000 130,000 130,000 130,000
310,000 130,000 130,000 130,000 130,000 130,000
370,000 130,000 130,000 130,000 130,000 130,000
430,000 130,000 130,000 130,000 130,000 130,000
490,000 130,000 130,000 130,000 130,000 130,000
550,000 130,000 130,000 130,000 130,000 130,000
Compensation covered for the executive officers named in Summary
Compensation Table on page 91 is the same as the total salary and bonus shown
in that table. Employees, including executive officers, may elect lump-sum
distributions in lieu of the receipt of annual retirement benefits.
ITEM 12 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
STOCK OWNERSHIP OF DIRECTORS AND OFFICERS
The following table sets forth the beneficial ownership of Common Stock of
the Company of all directors, four named executive officers, and all directors
and officers as a group as of December 31, 1997.
BENEFICIAL OWNERSHIP
(SHARES OF COMMON STOCK) (1)
----------------------------
Gerald A. Hale.............................. 6,650
Matthew Holden, Jr. ........................ 5,487
Cyrus H. Holley............................. 4,987
Jerrold L. Jacobs (a)....................... 7,380
Kathleen MacDonnell......................... 3,034
Richard B. McGlynn (b)...................... 4,110
Bernard J. Morgan........................... 4,887
Harold J. Raveche........................... 3,749
Michael J. Barron (c)....................... 0
Michael J. Chesser.......................... 5,792
Meredith I. Harlacher, Jr. (d).............. 31,546
Marilyn T. Powell........................... 1,257
All Directors and Officers as a Group (17
individuals)............................... 89,911
- --------
(1) Each of the individuals listed beneficially owned less than 1% of the
Company's outstanding Common Stock.
(a) Share ownership shown for Mr. Jacobs includes 5,138 shares held jointly
with his spouse.
(b) Share ownership shown for Mr. McGlynn includes 200 shares held in a
pension trust of which Mr. McGlynn is the trustee.
(c) Mr. Barron held no Company Common Stock as of December 31, 1997.
(d) Share ownership for Mr. Harlacher includes 7,254 shares held jointly with
his spouse.
ITEM 13 CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
95
PART IV
ITEM 14 EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Exhibits:
See Exhibit Index attached.
The following financial information, financial statements and notes to
financial statements for the Company and ACE are filed herein:
Management's Discussion and Analysis of Financial Condition and Results of
Operations; Consolidated Statement of Income for the three years ended
December 31, 1997; Consolidated Statement of Cash Flows for the three years
ended December 31, 1997; Consolidated Balance Sheet -- December 31, 1997 and
December 31, 1996; Consolidated Statement of Changes in Common Shareholder's
Equity; Notes to Consolidated Financial Statements; Independent Auditors'
Report.
Reports on Form 8-K:
Current Reports on Form 8-K were filed, dated January 6, 1997, January 27,
1997, January 31, 1997, March 24, 1997, July 15, 1997, December 30, 1997,
February 27, 1998, March 3, 1998 and March 5, 1998 relating to the subsequent
events, of Salem Units 1 and 2, the approvals of the merger agreement between
the Company and Delmarva Power & Light Company, and the BPU's order of Phase
II of the New Jersey Energy Master Plan, the issuances of First Mortgage
Bonds, ACE's restructuring filing, change in Auditors, change in Control and
the effective date of the merger.
96
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, ON MARCH 30,
1998.
Atlantic City Electric Company
(Registrant)
/s/ Barbara S. Graham
By: _________________________________
BARBARA S. GRAHAM SENIOR VICE
PRESIDENT AND CHIEF FINANCIAL
OFFICER
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS IN THE CAPACITIES, ON
MARCH 30, 1998.
SIGNATURE TITLE
/s/ Howard E. Cosgrove Chairman of the Board, Chief
_____________________________________ Executive Officer and
(HOWARD E. COSGROVE) Director
/s/ Barbara S. Graham Senior Vice President, Chief
_____________________________________ Financial Officer and
(BARBARA S. GRAHAM) Director
/s/ James P. Lavin Controller & Chief Accounting
_____________________________________ Officer
(JAMES P. LAVIN)
/s/ Barry R. Elson Director
_____________________________________
(BARRY R. ELSON)
/s/ Meredith I. Harlacher, Jr. Director
_____________________________________
(MEREDITH I. HARLACHER, JR.)
/s/ Thomas S. Shaw Director
_____________________________________
(THOMAS S. SHAW)
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, ON MARCH 30,
1998.
CONECTIV
(REGISTRANT)
/s/ Barbara S. Graham
By: _________________________________
BARBARA S. GRAHAM SENIOR VICE
PRESIDENT AND CHIEF FINANCIAL
OFFICER
97
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS IN THE CAPACITIES, ON
MARCH 30, 1998.
SIGNATURE TITLE
/s/ Howard E. Cosgrove Chairman of the Board, Chief
_____________________________________ Executive Officer and Director
(HOWARD E. COSGROVE)
/s/ Barbara S. Graham Senior Vice President, Chief
_____________________________________ Financial Officer and Director
(BARBARA S. GRAHAM)
/s/ James P. Lavin Controller & Chief Accounting
_____________________________________ Officer
(JAMES P. LAVIN)
/s/ Michael G. Abercrombie Director
_____________________________________
(MICHAEL G. ABERCROMBIE)
/s/ R. Franklin Balotti Director
_____________________________________
(R. FRANKLIN BALOTTI)
/s/ Robert D. Burris Director
_____________________________________
(ROBERT D. BURRIS)
/s/ Audrey K. Doberstein Director
_____________________________________
(AUDREY K. DOBERSTEIN)
/s/ Michael B. Emery Director
_____________________________________
(MICHAEL B. EMERY)
/s/ Sarah I. Gore Director
_____________________________________
(SARAH I. GORE)
/s/ Cyrus H. Holley Director
_____________________________________
(CYRUS H. HOLLEY)
/s/ Jerrold L. Jacobs Director
_____________________________________
(JERROLD L. JACOBS)
/s/ Kathleen MacDonnell Director
_____________________________________
(KATHLEEN MACDONNELL)
98
SIGNATURE TITLE
/s/ Richard B. McGlynn Director
_____________________________________
(RICHARD B. MCGLYNN)
/s/ Bernard J. Morgan Director
_____________________________________
(BERNARD J. MORGAN)
/s/ Weston E. Nellius Director
_____________________________________
(WESTON E. NELLIUS)
/s/ Harold J. Raveche Director
_____________________________________
(HAROLD J. RAVECHE)
99
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). Certificate
on Merger between Atlantic Energy, Inc. and Conectiv, Inc. filed
herewith.
3b By-Laws of Atlantic Energy, Inc. as amended July 13, 1995 (File No. 1-
9760, Form 10-Q for the quarter ended June 30, 1995 -- Exhibit 3b(1).
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).
4b 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 November 1, 1994 (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); Form 10-K for year ended December 31, 1994 --
Exhibit 4(c)(1).
4b(1) Indenture dated as of March 1, 1997 between Atlantic City Electric
Company and The Bank of New York filed on Form 8-K, dated March 24,
1997, File No. 1-3559 -- Exhibit 4(e).
4b(2) Indenture Supplemental dated as of March 1, 1997 to Mortgage and Deed
of Trust dated January 15, 1937 between Atlantic City Electric Company
and The Bank of New York filed on Form 8-K dated March 24, 1997, File
No 1-3559, Exhibit 4(b).
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) Amended and Restated Trust Agreement, dated as of October 1, 1996, by
and among Atlantic City Electric Company, as Depositor, The Bank of
New York, as Property Trustee, The Bank of New York (Delaware) as
Delaware Trustee and the Administrative Trustees Named Therein, (File
No. 1-9760, Form 10-K for year ended December 31, 1996 -- Exhibit No.
4f(7)).
100
4f(2) Junior Subordinated Indenture, dated as of October 1, 1996, by and
between Atlantic City Electric Company and The Bank of New York, as
Trustee, (File No. 1-9760, Form 10-K for year ended December 31,
1996 -- Exhibit No. 4f(8)).
4f(3) Guarantee Agreement, dated as of October 1, 1996, by and between
Atlantic City Electric Company as Guarantor, and The Bank of New York
as Guarantee Trustee, (File No. 1-9760, Form 10-K for year ended
December 31, 1996 -- Exhibit No. 4f(9)).
10a(1) Termination Agreement dated August 14, 1997 between Atlantic Energy,
Inc. and Michael J. Chesser, filed herewith.
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)).
12 Computation of Ratios of Earnings to Fixed Charges, filed herewith.
23 Independent Auditors' Consent, filed herewith.
24 Powers of Attorney for Atlantic City Electric Company dated as of
March 12, 1998, filed herewith.
27 Financial Data Schedules for Atlantic Energy, Inc. and Atlantic City
Electric Company for periods ended December 31, 1997.
101