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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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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, 1995
COMMISSION FILE NUMBER 1-9120
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Exact name of registrant as specified in its charter)
NEW JERSEY 22-2625848
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
80 PARK PLAZA, P.O. BOX 1171 07101-1171
NEWARK, NEW JERSEY (Zip Code)
(Address of principal executive offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 201 430-7000
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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Common Stock without par value New York Stock Exchange
Philadelphia Stock Exchange
COMMISSION FILE NUMBER 1-973
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(Exact name of registrant as specified in its charter)
NEW JERSEY 22-1212800
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
80 PARK PLAZA, P.O. BOX 570 07101-0570
NEWARK, NEW JERSEY (Zip Code)
(Address of principal executive offices)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 201 430-7000
DOCUMENTS INCORPORATED BY REFERENCE
PART OF FORM 10-K DOCUMENTS INCORPORATED BY REFERENCE
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III Portions of the definitive Proxy Statement for the Annual Meeting
of Stockholders of Public Service Enterprise Group Incorporated
to be held April 16, 1996, which definitive Proxy Statement is
expected to be filed with the Securities and Exchange Commission
on or about March 1, 1996, as specified herein.
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS TITLE OF EACH CLASS WHICH REGISTERED
------------------- -------------------- ------------------------
Cumulative Preferred Stock First and Refunding
$100 par value Series: Mortgage
Bonds Series Due:
4.08%
4.18% 8 3/4% Z 1999
4.30% 9 1/8% BB 2005
5.05% 9 1/4% CC 2021
5.28% 8 7/8% DD 2003
5.97% 8 3/4% EE 2021
6.80% 7 7/8% FF 2001
7.40% 7 1/8% GG 1997
7.44% 8 3/4% HH 2022
7.52% 7 5/8% II 2000
7.70% 6 7/8% KK 1997 New York Stock Exchange
8 1/2% LL 2022
6 7/8% MM 2003
6 % NN 1998
Cumulative Preferred Stock 7 1/2% OO 2023
$25 par value Series: 6 1/2% PP 2004
6 % QQ 2000
6.75% 6 1/8% RR 2002
7 % SS 2024
7 3/8% TT 2014
6 3/4% UU 2006
6 3/4% VV 2016
6 1/4% WW 2007
8 % 2037
5 % 2037
Monthly Income Preferred
Securities
$25 par Value Series
9.375%
8.00%
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
REGISTRANT TITLE OF CLASS
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Public Service Enterprise Group None
Incorporated
Public Service Electric and Gas 6.92% Cumulative Preferred Stock $100
Company par value
Medium-Term Notes, Series A
Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have been
subject to such filing requirements for the past 90 days. Yes X No .
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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 10-K. X
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The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated
held by non-affiliates as of January 31, 1996 was $7,642,239,750 based upon the New York Stock
Exchange Composite Transaction closing price.
The number of shares outstanding of Enterprise's sole class of common stock, as of the latest
practicable date, was as follows:
CLASS OUTSTANDING AT JANUARY 31, 1996
------------------------------- -------------------------------
Common Stock, without par value 244,697,930
As of January 31, 1996, Public Service Electric and Gas Company had issued and outstanding
132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held,
beneficially and of record by Public Service Enterprise Group Incorporated (Enterprise).
TABLE OF CONTENTS
PAGE
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Table of Contents........................................... i
Glossary of Terms........................................... v
PART I
Item 1. Business..................................... 1
General...................................... 1
Enterprise................................. 1
PSE&G...................................... 2
Industry Issues.............................. 3
Competition.................................. 3
Overview................................... 3
Electric................................... 5
Gas........................................ 7
Construction and Capital Requirements........ 7
Financing Activities......................... 7
Federal Income Taxes......................... 8
Credit Ratings............................... 8
PSE&G........................................ 9
Rate Matters............................... 9
Nuclear Performance Standard............... 9
Customers.................................. 10
Integrated Resource Plan................... 12
Pennsylvania -- New Jersey -- Maryland
Interconnection........................ 12
Power Purchases.......................... 14
Demand Side Management................... 15
Electric Generating Capacity............... 16
Nuclear Operations....................... 17
Salem.................................... 18
Hope Creek............................... 22
Peach Bottom............................. 24
Other Nuclear Matters.................... 25
Nuclear Decommissioning.................. 26
Electric Fuel Supply and Disposal.......... 27
Nuclear Fuel............................. 28
Coal..................................... 29
Natural Gas.............................. 30
Oil...................................... 30
Nuclear Fuel Disposal.................... 30
i
PAGE
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Low Level Radioactive Waste (LLRW)......... 32
Gas Operations and Supply.................. 33
Employee Relations........................... 35
Regulation................................... 35
Environmental Controls....................... 39
Air Pollution Control...................... 41
Water Pollution Control.................... 44
Control of Hazardous Substances............ 46
PSE&G Manufactured Gas Plant Remediation
Program................................. 46
Other Sites................................ 46
Hazardous Substances....................... 47
Other Potential Liability.................. 53
Consolidated Financial Statistics of
Enterprise............................... 54
Operating Statistics of PSE&G................ 55
EDHI......................................... 56
EDC........................................ 56
CEA........................................ 57
PSRC....................................... 57
EGDC....................................... 58
Capital.................................... 58
Funding.................................... 59
Item 2. Properties................................... 60
PSE&G...................................... 60
Electric Properties...................... 61
Gas Properties........................... 62
Office Buildings and Facilities............ 63
Item 3. Legal Proceedings............................ 64
Item 4. Submission of Matters to a Vote of Security
Holders.................................... 66
Item 10. Executive Officers of the Registrants........ 67
PART II
Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters................ 68
Item 6. Selected Financial Data...................... 70
Enterprise................................. 70
PSE&G...................................... 70
Item 7. Management's Discussion and Analysis of
Financial Condition and Results
of Operations............................... 71
Enterprise................................... 71
Overview................................... 71
Competition................................ 72
Accounting for the Effects of Regulation... 76
PSE&G Energy and Fuel Adjustment Clauses... 77
ii
PAGE
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Accounting for Stock Compensation......... 77
Corporate Policy for the Use of Derivatives 78
Nuclear Operations........................ 78
Results of Operations..................... 79
PSE&G - Earnings Available to Enterprise.. 79
PSE&G - Revenues.......................... 80
Electric................................ 80
Gas..................................... 80
PSE&G - Expenses.......................... 81
Fuel Expenses.......................... 81
Other Operation Expenses............... 81
Maintenance Expenses................... 82
Depreciation and Amortization Expenses. 82
Federal Income Taxes................... 82
Interest Charges....................... 82
Allowance for Funds Used During
Construction........................ 82
Preferred Securities................... 83
EDHI - Net Income...................... 83
Dividends.............................. 84
Liquidity and Capital Resources........... 84
PSE&G.................................. 85
EDHI................................... 85
Long-Term Investments and Real Estate.. 86
Construction, Investments and Other
Capital Requirements Forecast....... 87
Internal Generation of Cash from
Operations........................... 88
External Financings........................ 88
PSE&G................................... 88
EDHI.................................... 89
PSE&G........................................ 90
Item 8. Financial Statements and Supplementary Data.. 91
Financial Statement Responsibility
(Enterprise)............................. 91
Financial Statement Responsibility (PSE&G). 93
Independent Auditors' Report (Enterprise).. 95
Independent Auditors' Report (PSE&G)....... 96
Consolidated Statements of Income
(Enterprise)............................. 97
Consolidated Balance Sheets (Enterprise)... 98
Consolidated Statements of Cash Flows
(Enterprise)............................. 100
Consolidated Statements of Retained Earnings
(Enterprise)............................ 101
Consolidated Statements of Income (PSE&G).. 102
Consolidated Balance Sheets (PSE&G)........ 103
Consolidated Statements of Cash Flows
(PSE&G).................................. 105
Consolidated Statements of Retained Earnings
(PSE&G).................................. 106
Notes to Consolidated Financial Statements
(Enterprise)............................. 107
Notes to Consolidated Financial Statements
(PSE&G).................................. 152
iii
PAGE
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PART III
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure...... 156
Item 10. Directors and Executive Officers of the
Registrants............................... 156
Directors of the Registrants................ 156
Enterprise................................ 156
PSE&G..................................... 156
Executive Officers of the Registrants......... 157
Item 11. Executive Compensation........................ 159
Enterprise.................................. 159
PSE&G....................................... 159
Summary Compensation Table................ 159
Option Grants in Last Fiscal Year (1995).. 161
Aggregated Option Exercises in Last
Fiscal Year and Fiscal Year-End
Option Values (12/31/95)................ 161
Employment Contracts and Arrangements..... 161
Compensation Committee Interlocks and
Insider Participation................... 162
Compensation of Directors and Certain
Business Relationships.................. 162
Compensation Pursuant to Pension Plans.... 162
Item 12. Security Ownership of Certain Beneficial Owners
and Management........................... 162
Enterprise.................................. 162
PSE&G....................................... 163
Item 13. Certain Relationships and Related Transactions.163
Enterprise.................................. 163
PSE&G....................................... 163
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K..................... 164
Schedule II -- Valuation and Qualifying Accounts
(Enterprise)............................. 166
Schedule II -- Valuation and Qualifying Accounts (PSE&G)... 167
Signatures -- Public Service Enterprise Group
Incorporated............................ 168
Signatures -- Public Service Electric and Gas Company... 169
Exhibit Index.............................................. 170
Enterprise................................................. 170
PSE&G...................................................... 177
iv
GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or
acronyms that are found in this report:
TERM MEANING
----------------------- -----------------------------------------
ACO.................... Administrative Consent Order
AFDC................... Allowance for Funds used During Construction
Alternative Rate Plan.. New Jersey Partners in Power Plan
AMT.................... Alternative Minimum Tax
BCFE................... Billion Cubic Feet Equivalent
Bonds.................. First and Refunding Mortgage Bonds
BPU.................... New Jersey Board of Public Utilities
BTA.................... Best Technology Available
BWR.................... Boiling Water Reactor
CAA.................... Federal Clean Air Act
Capital................ PSEG Capital Corporation
CEA.................... Community Energy Alternatives Incorporated
CEA USA................ CEA USA, Inc.
CEA New Jersey......... CEA New Jersey, Inc.
CERCLA................. Federal Comprehensive Environmental
Response, Compensation and Liability
Act of 1980
Certificate of Need.... Certificate of Need under the NJNAA
CORP................... New Jersey Commission on Radiation Protection
DGW.................... Discharge to Ground Water
DOE.................... United States Department of Energy
DRBC................... Delaware River Basin Commission
DRIP................... Enterprise's Dividend Reinvestment and Stock
Purchase Plan
DSM.................... Demand Side Management
DSW.................... Discharge to Surface Water
Eagle Point............ CEA Eagle Point, Inc.
EBIT................... Earnings before interest and taxes
ECRA................... New Jersey Environmental Cleanup
Responsibility Act
EDC.................... Energy Development Corporation
EDHI................... Enterprise Diversified Holdings Incorporated
EGDC................... Enterprise Group Development Corporation
EITF................... FASB's Emerging Issues Task Force
EMF.................... Electric and Magnetic Fields
Enterprise............. Public Service Enterprise Group Incorporated
EPA.................... United States Environmental Protection Agency
v
TERM MEANING
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EPAct.................. National Energy Policy Act of 1992
EPC.................... Eagle Point Cogeneration Faclility
EWGs................... Exempt Wholesale Generators
FASB................... Financial Accounting Standards Board
Fault Act.............. New Jersey Public Utility Accident Fault
Determination Act
FERC................... Federal Energy Regulatory Commission
Fuelco................. PSE&G Fuel Corporation
Funding................ Enterprise Capital Funding Corporation
FWPCA.................. Federal Water Pollution Control Act
GE..................... General Electric
GEMS................... Gloucester Environmental Management
Services, Inc.
Hope Creek............. Hope Creek Nuclear Generating Station
IPP.................... Independent Power Producers
IRP.................... Integrated Resource Plan
IRS.................... Internal Revenue Service
ISO.................... Independent System Operator
KWH.................... Kilowatthours
LEAC................... Electric Levelized Energy Adjustment Clause
LGAC................... Levelized Gas Adjustment Charge
LLRW................... Low Level Radioactive Waste
LNG.................... Liquefied Natural Gas
LPG.................... Liquid Petroleum Air Gas
LTIP................... Long-Term Incentive Plan
MAAC................... Mid-Atlantic Area Reliability Council
MD&A................... Management's Discussion and Analysis of
Financial Condition and Results of
Operations
MICP................... Management Incentive Compensation Plan
mmbtu.................. Millions of British Thermal Units
MOA.................... Memorandum of Agreement
Mortgage............... First and Refunding Mortgage of PSE&G
MTNs................... Medium-Term Notes
MW..................... Megawatts
MWH.................... Megawatthours
NAAQS.................. National Ambient Air Quality Standards
NEIL................... Nuclear Electric Insurance Limited
NJAPCC................. New Jersey Air Pollution Control Code
NJDEP.................. New Jersey Department of Environmental
Protection
NJGRT.................. New Jersey Gross Receipts and Franchise Tax
NJNAA.................. New Jersey Need Assessment Act
vi
TERM MEANING
----------------------- ---------------------------------------------
NJPDES................. New Jersey Pollution Discharge Elimination
System
NJWPCA................. New Jersey Water Pollution Control Act
NML.................... Nuclear Mutual Limited
NOC.................... Nuclear Oversight Committee
NOPR................... Notice of Proposed Rulemaking
NOV.................... Notice of Violation
NOx.................... Nitrogen Oxides
NPDES.................. National Pollutant Discharge Elimination
System
NPS.................... The BPU's nuclear performance standard
established for nuclear generating stations
owned by New Jersey electric utilities
NRC.................... Nuclear Regulatory Commission
NUGs................... Nonutility Generators
NWPA................... Nuclear Waste Policy Act of 1982, as amended
OAL.................... Office of Administrative Law of the State of
New Jersey
OPEB................... Other Postretirement Benefits
OTAG................... Ozone Transport Assessment Group
Partnership............ Public Service Electric and Gas Capital, L.P.
Peach Bottom........... Peach Bottom Atomic Power Station,
Units 2 and 3
PECO................... PECO Energy Inc.
PJM.................... Pennsylvania -- New Jersey -- Maryland
Interconnection
PJP.................... PJP Landfill in Jersey City, New Jersey
POTW................... Publicly Owned Treatment Works
PPUC................... Pennsylvania Public Utility Commission
Price Anderson......... Price-Anderson liability provisions of the
Atomic Energy Act of 1954, as amended
PRAP................... Proposed Remedial Action Plan
PRPs................... Potentially Responsible Parties
PSE&G.................. Public Service Electric and Gas Company
PSCRC.................. Public Service Conservation Resources
Corporation
PSRC................... Public Service Resources Corporation
PUHCA.................. Public Utility Holding Company Act of 1935
PURPA.................. Public Utility Regulatory Policies
Act of 1978
PWR.................... Pressurized Water Reactor
QFs.................... Qualifying Facilities
RAC.................... Remediation Adjustment Charge
RACT................... Reasonable Available Control Technologies
RAR.................... Revenue Agent's Report
RCRA................... Federal Resource Conservation and Recovery
Act of 1976
vii
TERM MEANING
----------------------- ---------------------------------------------
Remediation Program.... PSE&G Gas Plant Remediation Program
RI..................... Remedial Investigation
RI/FS.................. Remedial Investigation and Feasibility Study
RIPW................... Remedial Investigation Work Plan
ROD.................... Record of Decision
Salem.................. Salem Nuclear Generating Station,
Units 1 and 2
SALP................... Systematic Assessment of Licensee Performance
SEC.................... Securities and Exchange Commission
SFAS 71................ Statement of Financial Accounting Standards
No. 71, "Accounting for the Effects of
Certain Types of Regulation"
SFAS 106............... Statement of Financial Accounting Standards
No. 106, "Employers' Accounting for
Postretirement Benefits Other than
Pensions"
SFAS 107............... Statement of Financial Accounting Standards
No. 107, "Disclosures About Fair Value of
Financial Instruments"
SFAS 109............... Statement of Financial Accounting Standards
No. 109, "Accounting for Income Taxes"
SFAS 121............... Statement of Financial Accounting Standards
No. 121, "Accounting for the Impairment of
Long-Lived Assets"
SFAS 123............... Statement of Financial Accounting Standards
No. 123, "Accounting for Stock Based
Compensation"
SIU.................... Significant Industrial Users
SNG Plant.............. Synthetic Natural Gas Plant
Spill Act.............. New Jersey Spill Compensation and Control Act
SPPP................... Stormwater Pollution Prevention Plans
USDOT.................. United States Department of Transportation
USEC................... United States Enrichment Corporation
USEP................... U.S. Energy Partners
Ventures............... Enterprise Ventures & Services
VOC.................... Volatile Organic Compound
viii
PART I
ITEM 1. BUSINESS
General
Enterprise
Public Service Enterprise Group Incorporated (Enterprise),
incorporated under the laws of the State of New Jersey with its
principal executive offices located at 80 Park Plaza, Newark, New
Jersey 07101, is a public utility holding company that neither owns nor
operates any physical properties. Enterprise has two direct
wholly-owned subsidiaries, Public Service Electric and Gas Company
(PSE&G) and Enterprise Diversified Holdings Incorporated (EDHI).
Enterprise's principal subsidiary, PSE&G, is an operating public
utility providing electric and gas service in certain areas in the
State of New Jersey. Enterprise has claimed an exemption from
regulation by the Securities and Exchange Commission (SEC) as a
registered holding company under the Public Utility Holding Company Act
of 1935 (PUHCA), except for Section 9(a)(2) thereof which relates to
the acquisition of voting securities of an electric or gas utility
company. PSE&G is subject to direct regulation by the New Jersey Board
of Public Utilities (BPU) and the Federal Energy Regulatory Commission
(FERC). EDHI is the parent of Enterprise's nonutility businesses:
Energy Development Corporation (EDC), an oil and gas exploration and
production and marketing company; Community Energy Alternatives
Incorporated (CEA), an investor in and developer and operator of
cogeneration and independent power production facilities; Public
Service Resources Corporation (PSRC), which makes primarily passive
investments; Enterprise Group Development Corporation (EGDC), a
diversified nonresidential real estate development and investment
business; PSEG Capital Corporation (Capital), which provides debt
financing on the basis of a minimum net worth maintenance agreement
from Enterprise; and Enterprise Capital Funding Corporation (Funding),
which provides privately placed debt financing on the basis of the
consolidated financial position of EDHI without direct support from
Enterprise. As of December 31, 1995 and 1994, PSE&G comprised 85% of
Enterprise's assets. PSE&G's 1995, 1994 and 1993 revenues were 93% of
Enterprise's revenues and PSE&G's earnings available to Enterprise for
such years were 88%, 91% and 96%, respectively, of Enterprise's net
income. Production of electricity and electric and gas distribution
will continue as the principal business of Enterprise for the
foreseeable future. Enterprise has announced that it intends to divest
EDC in 1996. See EDHI - EDC and Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations (MD&A).
Financial information with respect to business segments of PSE&G
and Enterprise is set forth in Note 15 -- Financial Information by
Business Segments of Notes to Consolidated Financial Statements
(Notes).
PSE&G
PSE&G, a New Jersey corporation with its principal executive
offices at 80 Park Plaza, Newark, New Jersey 07101, is an operating
public utility company engaged principally in the generation,
transmission, distribution and sale of electric energy service and in
the transmission, distribution and sale of gas service in New Jersey.
PSE&G supplies electric and gas service in areas of New Jersey in which
approximately 5,500,000 persons, about 70% of the State's population,
reside. (See General -- Enterprise.)
PSE&G's electric and gas service area is a corridor of
approximately 2,600 square miles running diagonally across New Jersey
from Bergen County in the northeast to an area below the City of Camden
in the southwest. The greater portion of this area is served with both
electricity and gas, but some parts are served with electricity only
and other parts with gas only. This heavily populated, commercialized
and industrialized territory encompasses most of New Jersey's largest
municipalities, including its six largest cities -- Newark, Jersey
City, Paterson, Elizabeth, Trenton and Camden -- in addition to
approximately 300 suburban and rural communities. It contains a
diversified mix of commerce and industry, including major facilities
of many corporations of national prominence.
Under the general laws of New Jersey, PSE&G has the right to use
the public highways, streets and alleys in New Jersey for erecting,
laying and maintaining poles, conduits and wires necessary for its
electric operations. PSE&G must, however, first obtain the consent in
writing of the owners of the soil for the purpose of erecting poles.
In incorporated cities and towns, PSE&G must obtain from the
municipality a designation of the streets in which the poles are to be
placed and the manner of placing them. PSE&G's rights are also subject
to regulation by municipal authorities with respect to street openings
and the use of streets for erecting poles in incorporated cities and
towns.
PSE&G, by virtue of a special charter granted by the State of New
Jersey to one of its predecessors, has the right to use the roads,
streets, highways and public grounds in New Jersey for pipes and
conduits for distributing gas.
PSE&G believes that it has all the franchises (including consents)
necessary for its electric and gas operations in the territory it
serves. Such franchises are non-exclusive.
For discussion of the significant changes which PSE&G's electric
and gas utility businesses have been and are undergoing, see
Competition and Regulation.
Industry Issues
Enterprise and PSE&G are affected by many issues that are common
to the electric and gas industries, such as: 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 (see Competition,
Regulation and MD&A - Competition); ability to operate nuclear plants
in a cost effective way (see PSE&G - Nuclear Operations); ability to
obtain adequate and timely rate relief, cost recovery, including the
potential impact of stranded assets, and other necessary regulatory
approvals (see PSE&G -- Rate Matters; Regulation and Item 7. MD&A -
Competition); costs of construction (see Construction and Capital
Requirements); operating restrictions, increased costs and construction
delays attributable to environmental regulations (see Environmental
Controls); controversies regarding electric and magnetic fields (EMF)
(see Environmental Controls); nuclear decommissioning and the
availability of reprocessing and storage facilities for spent nuclear
fuel (see Electric Fuel Supply and Disposal); and credit market
concerns with these issues.
Competition
Overview
The energy utility industry is in transition. Changes in Federal
and state law and regulation are encouraging new entrants to the
traditional markets of electric and gas utilities. New technologies are
creating opportunities for new energy services. Customers, more aware
and sophisticated about their choices and dissatisfied with prices and
the often limited range of options available from the local utility,
are increasingly turning elsewhere for energy supplies and services.
As a consequence of competition, the traditional utility structure --
consisting of a vertically integrated system and functioning as a
natural monopoly -- is being dramatically altered. Further, PSE&G's
ability to meet competition and change prices to meet customer's needs
is impacted by state regulation, including the historic utility mandate
to serve all customers. (See MD&A -- Competition.) For a discussion
of PSE&G's alternative plan of rate regulation, "New Jersey Partners
in Power" (Alternative Rate Plan) as a response to these demands, see
MD&A and Note 2 -- Rate Matters of Notes.
Non health and safety related Federal energy laws and regulations
are designed to make more efficient use of all energy, introduce price
competition, encourage the use of nonconventional energy sources and
limit oil imports by increasing production of domestic energy
resources. Among other things, these actions (1) encourage development
of alternative energy generation, (2) require wheeling of power for
wholesale transactions, (3) require state regulatory authorities to
consider certain standards on rate design and certain other utility
practices, (4) encourage conservation of energy through certain
financial incentives, including incentives by individual utilities to
customers to help them to conserve energy and (5) deregulate prices on
natural gas.
Also, Federal and State laws designed to reduce air and water
pollution and control hazardous substances have had the effect of
increasing the costs of operation and replacement of existing utility
plants and other facilities. (See Environmental Controls.)
Competition from nonutility generators (NUGs), such as
cogenerators, independent power producers (IPP) and exempt wholesale
generators (EWGs), as permitted by the Public Utility Regulatory
Policies Act of 1978 (PURPA) and the National Energy Policy Act of 1992
(EPAct), continues to impact PSE&G. As a result of changes brought
about by EPAct, along with proposals in some states to authorize retail
wheeling, discussed below, electric customers and suppliers, including
PSE&G and its customers, have increased opportunities for purchase and
sale of electricity from and to sellers and buyers outside of
traditional franchised territories. Retention of existing customers
and potential sales growth will depend upon the ability of PSE&G to
contain costs, meet customer expectations and respond to changing
economic conditions and energy regulation. As a result of such
competitive forces, Enterprise Ventures & Services Corporation
(Ventures) has been established as a subsidiary of PSE&G to develop and
market new energy-related products and services beyond traditional
geographic and/or industry boundaries. Competition may also adversely
impact upon the economics of certain regulatory-created incentives,
such as Demand Side Management (DSM) and conservation. For additional
information, including a discussion of the potential effects of
competition upon rates, cost recovery and assets, see MD&A --
Competition. For information relating to the Alternative Rate Plan see
MD&A and Note 1--Organization and Summary of Significant Accounting
Policies, Note 2--Rate Matters and Note 5--Deferred Items of Notes.
Electric
In the electric utility industry, competitive pressures began with
the enactment of PURPA. This law, together with subsequent changes in
Federal regulation, has increasingly opened the electric utility
industry to competition. PURPA created a class of generating
facilities exempt from Federal and State public utility regulation --
cogeneration and small power producers known as "qualifying facilities"
(QFs) -- and created an instant market for them by requiring regulated
utilities to purchase their excess power production. EPAct, by
facilitating the development of the wholesale power market, has led to
even stronger competition. The increasing competitiveness of the
electric wholesale markets, along with consideration of retail wheeling
or "direct retail access" within utility franchise areas in several
states, has brought to the forefront the issue of potential stranded
costs within the electric utility industry (see MD&A - Competition).
EPAct provides FERC with increased authority to order "wheeling"
of wholesale, but not retail, electric power on the transmission
systems of electric utilities, provided that certain requirements are
met. In order to facilitate the transition to increased competition in
wholesale power markets made possible by EPAct, in March 1995, FERC
issued a Notice of Proposed Rulemaking (NOPR) which, if adopted, would
require electric utilities, including PSE&G, to provide open access to
the interstate transmission network pursuant to non-discriminatory
tariffs available to all wholesale sellers and buyers of electric
energy. Utilities would be required to offer transmission to eligible
customers comparable to the service they provide themselves and to take
service under the tariffs for their own wholesale sales and purchases.
Further, transmission and ancillary service components would be
unbundled and, when buying or selling power, utilities would have to
rely on the same network for transmission system information as their
customers.
The NOPR states FERC's general principle that utilities should be
entitled to full recovery of legitimate and verifiable stranded costs
at the Federal and State levels and reiterates its prior proposal that
such costs be directly assigned to departing customers. The NOPR
further provides that stranded costs due to retail wheeling are a state
matter, while stranded costs due to wholesale wheeling,
municipalization or a change from retail to wholesale customer class
are within FERC's jurisdiction. PSE&G cannot predict the impact of any
regulations that may be adopted. See MD&A -- Competition. For
discussion of the Pennsylvania, New Jersey and Maryland Interconnection
(PJM) proposal in response to the FERC NOPR, see Pennsylvania--New
Jersey--Maryland Interconnection. For a discussion of PSE&G's actions
and comments related to the potential environmental impact of the NOPR,
see Environmental Controls - Air Pollution Control.
EPAct also amended PUHCA to create a new category of generation
owners known as EWGs, which are not subject to PUHCA regulation. EPAct
permits both independent companies and utility affiliates to
participate in the development of EWG projects regardless of the
location and ownership of other generating resources. The transmission
access provisions apply to wholesale, but not retail, "wheeling" of
power, subject to FERC review. See PSE&G -- Integrated Resource Plan,
Construction and Capital Requirements, Financing Activities and PSE&G
- -- Customers. For information concerning the activities of CEA, which
is an owner-developer of QFs and EWGs, see EDHI -- CEA.
Another key factor in determining how competition will affect
PSE&G's electric business is the extent to which New Jersey public
utility regulation may be modified to be reflective of these new
competitive realities. The BPU presented the first phase of the New
Jersey Energy Master Plan to Governor Whitman on March 8, 1995. This
Phase I Plan acknowledged the need for regulatory flexibility as
competition unfolds and called for legislation that would allow New
Jersey utilities to propose, subject to BPU approval, alternatives to
existing rate base/rate of return pricing, allow for pricing
flexibility under certain standards for customers with competitive
options and equalize the impact of tax policies, such as New Jersey
Gross Receipts and Franchise Tax (NJGRT) which is currently assessed
only on utility retail energy sales. On July 20, 1995, Governor
Whitman signed into law legislation which provides utilities the
flexibility to propose alternative regulatory pricing and to offer
negotiated off-tariff agreements (See PSE&G - Customers). On January
16, 1996, PSE&G filed a petition with the BPU for its Alternative Rate
Plan designed to fulfill the objectives of this new regulatory reform
legislation. This Alternative Rate Plan represents a regulatory
transition designed to provide PSE&G with the mechanisms and incentives
to compete more effectively on several fronts, including the ability
to develop revenue from non-regulated products and services, accelerate
or modify depreciation schedules to help mitigate any potential
stranded asset issue and more aggressively manage costs. For more
information regarding the Alternative Rate Plan see MD&A and Note 1 --
Organization and Summary of Significant Accounting Policies, Note 2 --
Rate Matters and Note 5 -- Deferred Items of Notes.
On June 1, 1995, the BPU issued its Order initiating a formal
Phase II proceeding to the New Jersey Energy Master Plan. This
proceeding is intended to investigate and consider the future long term
structure of the electric power industry in New Jersey. The proceeding
will address wholesale and retail competition, ownership of generation,
transmission and distribution facilities, operation of the transmission
system and stranded investments. A Phase II report proposing policy
restructuring is expected by March 1996. PSE&G cannot predict what
impact, if any, the Phase II report will have.
Gas
Over the last decade the natural gas industry has experienced a
dramatic transformation as several FERC initiatives have subjected the
industry to competitive market forces. On the interstate level, the
pipeline suppliers that serve PSE&G have unbundled gas supply and
service and now offer transportation services that move gas purchased
from numerous natural gas producers and marketers to PSE&G's service
territory.
This unbundling effort has moved to the local level and, in late
1994, the BPU approved unbundled transport tariffs for PSE&G. These
tariffs allow any non-residential customer, regardless of size, to
purchase its own gas, transport it to PSE&G and require PSE&G to
deliver such gas to the customer's facility. To date, over 5,000
commercial and industrial customers out of a potential of 180,000
customers have decided to utilize this service. It is expected that
this number will continue to grow as marketers become more active in
New Jersey and encourage customers to convert from sales service. The
transportation rate schedules produce the same non-fuel revenue per
therm as existing sales service rate schedules. Thus, PSE&G's earnings
are unaffected whether the customers remain on sales service or convert
to transportation service. See Gas Operations and Supply. In meeting
the challenges and opportunities presented by this unbundling of gas
supply and service, Enterprise initiated a gas marketing company, U.S.
Energy Partners (USEP). For more information see EDHI - PSRC.
Construction and Capital Requirements
For information concerning investments, construction and capital
requirements see MD&A, Note 6 -- Schedule of Consolidated Debt, Note
7 -- Long-Term Investments and Note 12 -- Commitments and Contingent
Liabilities -- Construction and Fuel Supplies of Notes.
Financing Activities
For a discussion of issuance, book value and market value of
Enterprise's Common Stock and external financing activities of
Enterprise, PSE&G and EDHI for the year 1995, see MD&A -- Liquidity and
Capital Resources and Item 5. Market for Registrant's Common Equity and
Related Stockholder Matters.
For a discussion of Capital and Funding, see EDHI -- Capital and
EDHI - Funding. For further discussion of long-term debt and
short-term debt, see Note 6 -- Schedule of Consolidated Debt of Notes.
Federal Income Taxes
For information regarding Federal income taxes, see Note 1 --
Organization and Summary of Significant Accounting Policies, Note 2 --
Rate Matters and Note 10 -- Federal Income Taxes of Notes.
Credit Ratings
The current ratings of securities of Enterprise's subsidiaries set
forth below reflect the respective views of the rating agency
furnishing the same, from whom an explanation of the significance of
such ratings may be obtained. There is no assurance that such ratings
will continue for any given period of time or that they will not be
revised downward or withdrawn entirely by such rating agencies, if, in
their respective judgments, circumstances so warrant. Any such downward
revision or withdrawal of any of such ratings may have an adverse
effect on the market price of Enterprise's Common Stock and PSE&G's
securities and serve to increase the cost of capital of PSE&G and EDHI.
STANDARD DUFF
PSE&G MOODY'S & POOR'S & PHELPS FITCH
- ----- ------- -------- -------- -----
Mortgage Bonds............ A3 A- A A-
Debenture Bonds........... Baa1 BBB+ A- BBB+
Preferred Stock........... Baa1 BBB+ A- BBB+
Commercial Paper.......... P2 A2 Duff 1
Fuelco: Commercial Paper.. P2 A2 Duff 1
As a component of the ratings noted above, each rating agency
issues its opinion of the credit trend or outlook for the entity being
rated. For PSE&G, each of the four rating agencies currently evaluate
that outlook as stable.
EDHI
- ----
Capital: Senior Debt......... Baa2 BBB BBB+
Funding: Commercial Paper(A). P1 A1+ Duff 1+
(A) Supported by commercial bank letter of credit (see MD&A --
Liquidity and Capital Resources and Note 6-- Schedule of Consolidated
Debt -- Short-Term of Notes.)
PSE&G
Rate Matters
For information concerning PSE&G's Alternative Rate Plan, rate
matters, and environmental remediation and fuel adjustment clauses see
Note 1 -- Organization and Summary of Significant Accounting Policies
and Note 2 -- Rate Matters of Notes. For information concerning
PSE&G's Under (Over) recovered Electric Energy and Gas Fuel Costs, see
Note 5 -- Deferred Items of Notes.
Nuclear Performance Standard
The BPU has established a nuclear performance standard (NPS) for
nuclear generating stations owned by New Jersey electric utilities,
including the five nuclear units in which PSE&G has an ownership
interest: Salem Nuclear Generating Station, Units 1 and 2 (Salem 1 and
2) -- 42.59%; Hope Creek Nuclear Generating Station (Hope Creek) --
95%; and Peach Bottom Atomic Power Station, Units 2 and 3 (Peach Bottom
2 and 3) -- 42.49%. PSE&G operates Salem and Hope Creek, while Peach
Bottom is operated by PECO Energy, Inc. (PECO). The following table
sets forth the capacity factor in accordance with the NPS of each of
PSE&G's nuclear units for the years indicated:
NUCLEAR UNITS 1995 1994 1993
- -------------- ---- ---- ----
Capacity Factors:
Salem 1..................................... 26% 59% 60%
Salem 2..................................... 21 58 57
Hope Creek.................................. 76 77 95
Peach Bottom 2.............................. 96 80 84
Peach Bottom 3.............................. 78 98 70
Aggregate capacity factor of nuclear units.. 62 74 77
For information concerning the NPS, see Nuclear Operations and
Note 12 -- Commitments and Contingent Liabilities of Notes.
Customers
As of December 31, 1995, PSE&G provided service to approximately
1,900,000 electric customers and 1,500,000 gas customers. PSE&G is not
dependent on a single customer or a few customers for its electric or
gas sales. For the year ended December 31, 1995, PSE&G's operating
revenues aggregated $5.7 billion, of which 70% was from its electric
operations and 30% from its gas operations. PSE&G's business is
seasonal in that sales of electricity are higher during the summer
months because of air conditioning requirements and sales of gas are
greater in the winter months due to the use of gas for space-heating
purposes.
These revenues were derived as follows:
Revenues
------------------
Electric Gas
--------- ------
(Millions of Dollars)
Residential................................ $1,275 $ 823
Commercial................................. 1,854 501
Industrial................................. 705 275
Transportation Service - Gas............... -- 54
Other...................................... 187 33
------ ------
Total................................... $4,021 $1,686
====== ======
Customers of PSE&G, as well as those of other New Jersey electric
and gas utilities, pay the NJGRT which, in effect, adds approximately
13% to their bills. The NJGRT is a unit tax based on electric
kilowatthour and gas therm sales. This tax differential provides an
incentive to large-volume electric and gas customers to seek to obtain
their energy supplies from nonutility sources not subject to NJGRT.
To the extent PSE&G experiences a loss of customers seeking to avoid
this cost, it could result in a significant decrease in PSE&G's
revenues and earnings.
On November 17, 1995, the BPU issued an order approving a
Stipulation regarding PSE&G's proposed Experimental Hourly Energy
Pricing Tariff and the first service agreement thereunder with its
second largest customer. Under the agreement, the tariff will result
in a bill reduction for the customer of approximately $7 million or
about 27%. This reduction in revenues will be partially offset by a
decrease of $1.25 million in PSE&G's NJGRT liability. Under the
agreement between the customer and PSE&G, the customer will forego an
opportunity to relocate to another state and remain a PSE&G customer
for ten years. On January 2, 1996, an appeal seeking to overturn the
BPU's November 17, 1995 Decision and Order was filed by a third party
in the Appellate Division of the Superior Court of New Jersey. PSE&G
cannot predict the outcome of this matter.
PSE&G has signed each of its three existing wholesale electric
customers, aggregating 40 mw of load, to 5-year full service agreements
with mid-term extension options. In addition, under the terms of a
previously negotiated 10-year wholesale power transaction, PSE&G
receives $12.5 million in annual revenues from an out of state electric
cooperative. For further information on the impact of competition on
PSE&G's customer and revenue base - See Competition and MD&A -
Competition.
Integrated Resource Plan
PSE&G's construction program focuses on upgrading electric and gas
transmission and distribution systems and constructing new transmission
and distribution facilities to serve new load.
Pursuant to its Integrated Resource Plan (IRP), PSE&G periodically
reevaluates its forecasted customer load and peak growth and the
sources of electric generating capacity and DSM to meet such projected
growth (see Demand Side Management below). The IRP takes into account
assumptions concerning future customer demand, future cost trends,
especially fuel and purchased power expenses, the effectiveness of
conservation and load management activities, the long-term condition
of and projected additions to PSE&G's plants and capacity available
from other electric utilities and nonutility suppliers. PSE&G's IRP
consists principally of plant additions, power purchases through PJM
and from NUGs and DSM.
Pennsylvania -- New Jersey -- Maryland Interconnection
PSE&G is a member of the PJM which integrates the bulk power
generation and transmission supply operations of 11 utilities in
Pennsylvania, New Jersey, Delaware, Maryland, Virginia and the District
of Columbia, and, in turn, is interconnected with other major electric
utility companies in the northeastern part of the United States. The
PJM is operated as one system and provides for the purchase and sale
of power among members on the basis of reliability of service and
operating economy. As a result, the most economical mix of generating
capability available is used to meet PJM daily load requirements.
PSE&G's output, as shown under Electric Fuel Supply and Disposal,
reflects significant amounts of purchased power because at times it is
more economical for PSE&G to purchase power from PJM and others than
to produce it. As of December 31, 1995, the aggregate installed
generating capacity of the PJM companies was 56,098 megawatts (MW).
The all time record peak one-hour demand experienced by the PJM power
pool was 48,524 MW which occurred on August 2, 1995. The 1995 peak was
2,532 MW higher than the record-setting 1994 summer peak of 45,992 MW
which occurred on July 8, 1994. PSE&G's capacity obligations to the
PJM system vary from year to year due to changes in system
characteristics. PSE&G expects to have sufficient installed capacity
to meet its obligations during the 1996-2000 period.
PJM has developed a comprehensive proposal intended to meet or
exceed the goals expressed by FERC in its open access NOPR, including
a number of innovations that were designed to harmonize the
requirements of the NOPR with the benefits of power pooling. In this
proposal, PJM intends to satisfy the NOPR's goals by building upon the
foundation of PJM's power pooling operations. The member companies of
PJM intend to file this proposal with FERC by May 1996 and implement
a restructured pool by year-end 1996.
Under this proposal, the current members of PJM and other load-
serving entities in the PJM control area will purchase regional
"network" transmission rights that are intended to enable them to
reliably and economically integrate generation and load. For
deliveries to retail customers, this service will remain part of the
bundled rates for retail electric service, subject to state
jurisdiction, but with terms and conditions comparable to the service
provided for wholesale users. Because this service will cover all
deliveries to loads located in the pool, generators selling power to
serve pool load will not have to purchase transmission service
independently. This is intended to create a regional wholesale power
market in which all sellers and buyers operate on a level playing
field.
Under the proposal, transmission service will be provided under
a regional point-to-point transmission service tariff. This tariff
will apply a uniform ratemaking methodology to all wholesale
transactions involving deliveries outside the pool, including off-
system sales by the current members of PJM and other load-serving
entities in the pool. Accordingly, all transmission service associated
with sales outside the pool will be provided on a comparable basis.
In order to meet the requirements to functionally unbundle
transmission, PJM has proposed to reorganize into an independent System
Operator (ISO) with responsibility for operating the bulk power system,
administering the regional transmission service tariffs and managing
the pool's competitive energy market. The ISO will be governed by a
Board of Directors that is not controlled by the transmission-owning
members of PJM or their affiliates, and its responsibilities will be
set forth in contracts filed with the FERC. The ISO will contract with
the various pool participants to supply control area services,
administer the transmission service tariffs and be responsible for
maintaining the reliable operation of the system throughout each day.
One of the key elements of PJM's restructuring proposal is the
creation of an expanded regional market for energy transactions. PJM
will replace the existing system of cost-based centralized dispatch
with an expanded, hourly bid/price pool in which all sellers will be
able to bid their energy into the pool and all load-serving entities
will be able to buy energy from the pool. The energy market will
"clear" in each hour at the highest bid price for energy that must be
dispatched to serve load.
Further, under the proposal, PJM will retain most of the existing
pool procedures for ensuring reliable electric service, but will create
new contractual mechanisms to ensure participation by all entities
responsible for serving load in decisions affecting reliability. Each
load-serving entity that chooses to operate in the PJM control area
will be required to execute an agreement to maintain adequate
generation reserves and to share those reserves on a reciprocal basis.
PJM will establish an enhanced regional planning process, under the
supervision of the ISO, to meet Mid-Atlantic Area Reliability Council
(MAAC) reliability requirements applicable to both generation and
transmission. In short, all load-serving entities in the pool will be
subject to the same reliability standards and will participate in
decisions relating to the establishment of regional reliability
requirements.
Power Purchases
A component of PSE&G's IRP consists of expected capacity additions
from NUGs. These additions are projected to aggregate 46 MW and are
scheduled for service by 1998. NUG projects are expected to comprise
approximately 6.5% of energy resources by 2004. This availability of
NUG generation will reduce the need for PSE&G to build or acquire
additional generation.
PSE&G is also a party to the MAAC which provides for review and
evaluation of plans for generation and transmission facilities and
other matters relevant to reliability of the bulk electric supply
systems in the Mid-Atlantic area.
PSE&G 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 outages of equipment, PSE&G could find it necessary at
times to reduce voltage or curtail load in order to safeguard the
continued operation of its system.
Demand Side Management
Integrated resource planning brings together demand-side and
supply-side strategies. In order to encourage DSM, the BPU adopted
rules in 1991 providing special incentives to encourage utilities to
offer these load management conservation services. The rules are
designed to place DSM on an equal regulatory footing with supply side
or energy production investments. Both EPAct and Phase I of the Energy
Master Plan call for conservation to play a significant role in meeting
New Jersey's energy needs over the coming decade. PSE&G's DSM Plan has
been approved by the BPU. The IRP calls for PSE&G to utilize
conservation and DSM to meet most of the incremental resource needs for
the next decade (see Competition).
PSE&G's DSM Plan is designed to encourage investment in
energy-saving DSM activities in New Jersey. These activities involve
new techniques and technologies, such as high-efficiency lighting and
motors, that help reduce customer demand for energy. The DSM Plan
consists of two major program areas for both electric and gas: (1) a
core program which includes many specialized programs such as energy
audits, seal-ups and rebates for high efficiency heating and cooling
equipment; and (2) a standard offer program which is performance based
and provides payment for measurable energy savings resulting from the
installation of qualified measures that improve the energy efficiency
of end-uses. PSE&G's most recent IRP includes a demand forecast average
compound annual rate of growth through the year 2004 of electric system
peak demand of 1.3%. PSE&G's IRP projects 597 MW of passive DSM and
815 MW of active DSM by the year 2004.
PSE&G has established a wholly owned subsidiary, Public Service
Conservation Resources Corporation (PSCRC), to offer DSM services.
PSCRC has its principal office at 9 Campus Drive, Parsippany, N.J.
07054. PSCRC finances, markets and develops energy conservation
projects, mostly within the PSE&G service territory. At December 31,
1995, its assets totaled $110 million, of which $88.2 million were
project assets and work in progress.
Electric Generating Capacity
The following table sets forth certain information as to PSE&G's
installed generating capacity as of December 31, 1995:
INSTALLED
SOURCE CAPACITY(MW) PERCENTAGE
- --------------- ------------ ----------
Conventional Steam Electric
Oil-fired(a)............................. 1,723 17
Coal-fired New Jersey(b)................. 1,242 12
Coal-fired Pennsylvania (mine mouth)(c).. 770 7
Combustion Turbine(d)...................... 2,724 26
Combined Cycle............................. 890 9
Diesel(c).................................. 5 --
Nuclear(c)
New Jersey............................... 1,921 18
Pennsylvania............................. 930 9
Pumped Storage(c)(d)....................... 195 2
------ ----
Total(e)......................... 10,400 100
====== ====
(a) Units with aggregate capacity of 836 MW can also burn gas.
(b) Can also burn gas.
(c) PSE&G share of jointly owned facilities.
(d) Primarily used for peaking purposes.
(e) Excludes 664 MW of nonutility generation and temporary capacity
sales of 200 MW to General Public Utilities Corporation.
For additional information, see Item 2. Properties -- PSE&G --
Electric Properties.
The capacity available at any time may be less than the installed
capacity because of temporary outages for inspection, maintenance,
repairs, legal and regulatory requirements or unforeseen circumstances.
The maximum one-hour demand (peak load) which PSE&G experienced
in 1995 was 9,467 MW, an all time record which occurred on August 2,
1995, when the day's output was 182,404 Megawatthours (MWH) of
electricity. (For information concerning sales, output and capacity
factors, see Operating Statistics.) The peak load in 1994 was 9,001 MW
which occurred on June 15, 1994, when the day's output was 172,362 MWH
of electricity.
Nuclear Operations
Operation of nuclear generating units involves continuous close
regulation by the Nuclear Regulatory Commission (NRC). Such regulation
involves testing, evaluation and modification of all aspects of plant
operation in light of NRC safety and environmental requirements and
continuous demonstrations to the NRC that plant operations meet
applicable requirements. The NRC has the ultimate authority to
determine whether any nuclear generating unit may operate. For
information concerning the performance of the nuclear units, see
Nuclear Performance Standard and Note 12 -- Commitments and Contingent
Liabilities of Notes.
The scheduled 1996, 1997, and 1998 refueling outages, each
estimated at eight to ten weeks duration, for PSE&G's five licensed
nuclear units are expected to commence in the following months:
REFUELING OUTAGES
--------------------------------------------
1996 1997 1998
------------- ------------- -------------
Salem 1.......... -- -- --
Salem 2.......... -- -- February
Hope Creek....... -- April October
Peach Bottom 2... September -- September
Peach Bottom 3... -- September --
Salem
Salem Generating Station consists of two 1100 MW pressurized water
nuclear reactors (PWR) located in southern New Jersey on the Delaware
River. PSE&G owns 42.59% of the Salem units and operates them on behalf
of itself and three other owners: PECO - 42.59%: Atlantic Electric
Company - 7.41%; and Delmarva Power and Light Company - 7.41%. As of
January 31, 1996, PSE&G's net book value for Salem nuclear production
units is approximately $285 million for Salem 1, $250 million for Salem
2 and $93 million in common plant between the two units. Each Salem
unit represents approximately 4% of PSE&G's installed electric
generating capacity and approximately 2% of its total assets.
Salem 1 and 2 have been out of service since May 16, 1995 and June
7, 1995, respectively. Since that time, PSE&G has been engaged in a
thorough assessment of each unit to identify and complete the work
necessary to achieve safe, sustained, reliable and economic operation.
PSE&G has stated that it will keep each unit off line until it is
satisfied that the unit is ready to return to service and to operate
reliably over the long term and the NRC has agreed that the unit is
sufficiently prepared to restart. On June 9, 1995, the NRC issued a
Confirmatory Action Letter documenting these commitments of PSE&G.
On December 11, 1995, PSE&G presented its restart plan for both
units to the NRC at a public meeting. On February 13, 1996, the NRC
staff issued a letter to PSE&G indicating that it had concluded that
PSE&G's overall restart plan, if implemented effectively, should
adequately address the numerous Salem issues to support a safe plant
restart, and describing further actions the NRC will undertake to
confirm that PSE&G's actions have resulted in the necessary performance
improvements to support safe plant restart.
As a part of PSE&G's comprehensive review, an extensive
examination is being performed on the steam generators, which are large
heat exchangers used to produce steam to drive the turbines. Within
the industry, certain PWRs other than Salem have experienced cracking
in a sufficient number of the steam generator tubes to require various
modifications to these tubes and replacement of the steam generators
in some cases. Until the current outage, regular periodic inspections
of the steam generators for each Salem unit have resulted in repairs
of a small number of tubes well within NRC limits. As a result of the
experience of other utilities with cracking in steam generator tubes,
in April 1995 the NRC issued a generic letter to all utilities with
pressurized water reactors. This generic letter requested utilities
with pressurized water reactors to conduct steam generator examinations
with more sensitive inspection devices capable of detecting evidence
of degradation. Subsequently, PSE&G conducted steam generator
inspections of the Salem units using the latest technology available,
including a new, more sensitive, eddy current testing device.
With respect to Salem 1, the most recent inspection of the steam
generators is not complete, but partial results from eddy current
inspections in February 1996 using this new technology show
indications of degradation in a significant number of tubes. The
inspections are continuing and PSE&G has decided to remove several
tubes for laboratory examination to confirm the results of the
inspections. Removal of the tubes should be completed in March and
preliminary results of the state of the Salem 1 tubes from the
subsequent laboratory examinations should be known in April. However,
based on the results of inspections to date, PSE&G has concluded that
the Salem 1 outage, which was expected to be completed in the second
quarter of 1996, will be required to be extended for a substantial
additional period to evaluate the state of the steam generators and to
subsequently determine an appropriate course of action. Degradation
of steam generators in PWRs has become of increasing concern for the
nuclear industry. Nationally and internationally, utilities have
undertaken actions to repair or replace steam generators. In the
extreme, degradation of steam generators has contributed to the
retirement of several American nuclear power reactors. After the Salem
1 tubes are fully examined, PSE&G will be able to evaluate its course
of action in light of NRC and other industry requirements.
The examination of the Salem 2 steam generators was completed in
January 1996 using the same testing device used in Salem 1. The
results of the Salem 2 inspection are being reviewed again to confirm
their results in light of the experience with Salem 1. Although this
review has not yet been completed, results to date appear to confirm
that the condition of the Salem 2 steam generators is well within
current repair limits at the present time. PSE&G will also remove
tubes from the Salem 2 steam generators for laboratory analysis to
further confirm the results of this testing.
PSE&G had planned to return Salem 1 to service in the second
quarter of 1996 and Salem 2 in the third quarter of 1996. As a result
of the extent of the recently discovered degradation in the Salem 1
steam generators, PSE&G is focusing its efforts on the return of Salem
2 to service in the third quarter. The conduct of the additional steam
generator inspections and testing on Salem 2 is not expected to
adversely affect the timing of its restart. However, the timing of the
restart is subject to completion of the requirements of the restart
plan to the satisfaction of PSE&G and the NRC as well as to the normal
uncertainties associated with such a substantial review and improvement
of the systems of a large nuclear unit, so that no assurance can be
given that the projected return date will be met.
PSE&G's share of additional operating and maintenance expenses
associated with Salem restart activities in 1995 was $16 million, and
capital was $1.9 million. PSE&G's share of total operating and
maintenance expenses for both Salem units for the year was $111 million
and capital costs were $50.8 million. For 1996, PSE&G does not
presently expect its share of operating and maintenance expenses or
capital costs for Salem station to exceed 1995 amounts; however this
could change as a result of the steam generator inspection results
referred to above. The outage of a Salem unit causes PSE&G to incur
replacement power costs of approximately $4 to $6 million per month.
Such amounts vary, however, depending on the availability of other
generation, the cost of purchased energy and other factors, including
modifications to maintenance schedules of other units.
PSE&G's 1995 aggregate capacity factor for its five nuclear units
was 62%, below the 65% minimum annual standard established by the BPU
(see Nuclear Performance Standard), resulting in a penalty of
approximately $3.5 million. Based upon current projections and
assumptions regarding PSE&G's five nuclear units during 1996, including
the return of Hope Creek to service in early March, the return of Salem
2 in the third quarter, and the continued outage of Salem 1 for the
remainder of the year, the 1996 aggregate capacity factor would be
approximately 57%, which would result in a penalty ranging from $11 to
$12 million. For a discussion of the proposed elimination of the NPS
under the proposed Alternate Rate Plan, see Note 2 -- Rate Matters of
Notes.
An NRC enforcement conference was held on July 28, 1995 related
to certain violations of NRC requirements at Salem. The violations
included valves that were incorrectly positioned following a plant
modification in May 1993, non-conservatisms in setpoints for a
pressurizer overpressure protection system and several examples of
inadequate root cause determination of events, leading to insufficient
corrective actions. On October 16, 1995, the NRC imposed cumulative
civil penalties of $600,000 related to these violations. PSE&G did not
contest the penalties.
On January 3, 1995, the NRC provided PSE&G with its latest
Systematic Assessment of Licensee Performance (SALP) report on Salem
for the period between June 20, 1993 and November 5, 1994. SALP is a
process pursuant to which the NRC periodically reviews the performance
of nuclear power plant operations. SALP reports rate licensee
performance in four assessment areas: Operations, Maintenance,
Engineering and Plant Support (the Plant Support area includes
security, emergency preparedness, radiological controls, fire
protection, chemistry and housekeeping). Ratings range from a high of
"1" to a low of "3" for each assessment area. Salem received a rating
of "3" in the Operations and Maintenance areas, a rating of "2" in
Engineering, and a rating of "1" in the Plant Support area. The NRC
noted an overall decline in performance and evidenced particular
concern with plant and operator challenges caused by repetitive
equipment problems and personnel errors. The NRC also noted that
although PSE&G has initiated several comprehensive actions within the
past year to improve plant performance, and some recent incremental
gains have been made, these efforts have yet to noticeably change
overall performance at Salem.
On March 21, 1995, representatives of the NRC Staff met with the
Boards of Directors of Enterprise and PSE&G to reiterate the previously
expressed concerns with regard to Salem's operations. The NRC staff
acknowledged that PSE&G had made efforts to improve Salem's operations,
including making senior management changes, but indicated that
demonstrated sustained results have not yet been achieved.
PSE&G's own assessments, as well as those by the NRC and the
Institute of Nuclear Power Operations, indicate that additional efforts
are required to further improve operating performance, as reflected in
the restart plans referred to above. PSE&G is committed to taking the
necessary actions to address Salem's performance needs. It is
anticipated that the NRC will continue to maintain a close watch on
Salem's restart activities and subsequent operational performance. No
assurance can be given as to what, if any, further or additional
actions may be taken or required by the NRC to improve Salem's
performance.
For certain litigation and potential claims relating to Salem, see
Item 3. Legal Proceedings and Note 12 -- Commitments and Contingent
Liabilities of Notes.
Hope Creek
An outage at Hope Creek causes PSE&G to incur replacement energy
costs of approximately $10 to $16 million per month. Such amounts vary,
however, depending upon the availability of other generation, the cost
of purchased energy and other factors including modifications to
maintenance schedules of other units.
Hope Creek is currently undergoing a refueling and maintenance
outage which commenced November 11, 1995. Replacement power costs
incurred during the outage are expected to be approximately $10 million
per month. Hope Creek is presently scheduled to return to service in
early March 1996.
As a result of an internal allegation report, PSE&G submitted a
Licensee Event Report to the NRC on October 14, 1994 which stated that
in 1992, the Hope Creek control room was understaffed for approximately
three minutes and a decision was made by those involved that the
incident did not warrant initiation of NRC reporting documentation.
A meeting with Region I NRC personnel was held on October 18, 1994 in
which the NRC expressed a high degree of concern over the issue. Both
the NRC and PSE&G investigated the validity of the allegation and, on
September 19, 1995, the NRC issued two Level IV violations with no
civil penalty for this incident.
A small amount of low-level radioactive material was released to
the atmosphere at Hope Creek on April 5, 1995. The release did not
exceed federal limits nor pose any danger to the public or plant
employees; however, a trailer driven offsite had exceeded the limit for
releasing materials and was later cleaned. PSE&G and the NRC
have investigated the event, and on June 16, 1995 an enforcement
conference was held. On July 20, 1995, the NRC issued a Notice Of
Violation for the Hope Creek unplanned release which noted four
violations. No fine was issued, partly because of the comprehensive
corrective actions taken following the event and the plant's history
of limited enforcement action.
On June 29, 1995, the NRC provided PSE&G with the latest periodic
SALP report for Hope Creek for the period between June 20, 1993 and
April 22, 1995. The Operations, Maintenance and Engineering areas each
received a rating of "2", while the Plant Support area received a
rating of "1". However, the NRC noted an overall decline in
performance in the Operations, Maintenance and Engineering areas
compared to the previous SALP period and cited weak root cause analysis
as a dominant factor.
On July 8, 1995, during a manual shutdown of Hope Creek in order
to repair control room ventilation equipment, operators partially
opened a valve for a period of time and inadvertently reduced the
effectiveness of the shutdown cooling system. Although the impact of
the event to plant safety was minimal, the positioning of the valve and
the resulting temperature change violated plant procedures and
technical specifications. On July 31, 1995, NRC staff met with plant
management concerning this issue and subsequently determined to assign
a special inspection team to independently evaluate this event as well
as PSE&G s response to it, including PSE&G s procedures and training
for operator handling of abnormal conditions. An NRC enforcement
conference was held on November 6, 1995. On December 12, 1995, the NRC
issued a Level III violation for this event, with a civil penalty of
$100,000. PSE&G did not challenge the fine.
By letter dated January 29, 1996, the NRC requested a meeting with
PSE&G senior management to discuss its concerns regarding declining
trends in performance at Hope Creek. The meeting has not yet been
scheduled but is expected to occur after the restart of Hope Creek from
its current refueling and maintenance outage.
Peach Bottom
The outage of a Peach Bottom unit causes PSE&G to incur additional
replacement energy costs of approximately $4 to $6 million per month
per unit. Such amounts vary, however, depending upon the availability
of other generation, the cost of purchased energy and other factors
including modifications to maintenance schedules of other units.
PSE&G has been advised by PECO that on January 19, 1996, the NRC
issued its periodic SALP Report for Peach Bottom for the period May 1,
1994 to October 14, 1995. Peach Bottom received a rating of "1" in the
areas of Plant Operations, Maintenance, and Plant Support. Engineering
received a rating of "2". The NRC found continued improvement in
performance during the period. Operator performance continued to be
a strength as well as operations management oversight. Effective
engineering management actions to improve the overall self assessment
and system performance evaluation programs were noted, as well as good
management oversight activities. Response to emerging issues,
equipment problems and event related issues were noted as particularly
strong. However, lapses in the quality of technical work and in
modification implementation indicated inconsistent performance, and
resulted in a repeat rating of "2" for the Engineering area. PECO has
advised PSE&G that it will be taking actions to address weaknesses
discussed in the SALP Report.
PSE&G has been advised by PECO that, by letter dated October 18,
1994, the NRC has approved PECO's request to re-rate the authorized
maximum reactor core power levels of both Peach Bottom units by 5% to
3,458 MW from the current limits of 3,293 MW. The amendment of the
Peach Bottom 2 facility operating license was effective upon the date
of the NRC approval letter and the hardware changes were completed
during the Fall 1994 refueling outage. The amendment of the Peach
Bottom 3 facility operating license became effective when the hardware
changes for Unit 3 were completed during its Fall 1995 refueling
outage.
PSE&G has been advised by PECO that on August 2, 1995, the NRC
held an enforcement conference regarding three alleged violations
identified by the NRC at Peach Bottom. The NRC s findings included
alleged violations in control and design activities and technical
specification requirements regarding operability of the emergency
diesel generators. As a result, on August 17, 1995, the NRC issued
PECO a Level III violation with no civil penalty.
Other Nuclear Matters
In 1990, General Electric (GE) reported that crack indications
were discovered near the seam welds of the core shroud assembly in a
GE Boiling Water Reactor (BWR) located outside the United States. As
a result, GE issued a letter requesting that the owners of GE BWR
plants take interim corrective actions, including a review of
fabrication records and visual examinations of accessible areas of the
core shroud seam welds. PSE&G (Hope Creek) and PECO (Peach Bottom)
participated in a GE BWR Owners' Group to evaluate this issue and
develop long-term corrective actions.
During the Spring 1994 refueling outage, PSE&G 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. Due to the age and materials of the Hope Creek shroud and the
historical maintenance of low conductivity water chemistry, Hope Creek
has been placed in the lowest susceptibility category under these
guidelines. Hope Creek must do another shroud inspection during its
next refueling outage in 1997, or install a preemptive repair that
would maintain the structural integrity of the shroud under all normal
and design basis accident conditions for the remaining life of the
plant.
PECO has advised PSE&G that Peach Bottom 3 was last examined
during its Fall 1995 refueling outage and the extent of cracking
identified was determined to be within industry-established guidelines.
In a letter to the NRC dated November 3, 1995, PECO concluded that
there is a substantial margin for each core shroud weld to allow for
continued operation of Unit 3. PECO has also advised that Peach Bottom
2 was examined in October 1994 during its refueling outage. Although
some crack indications were identified, PECO advised that they were
considered to be much less severe than those found on Unit 3, and no
repairs were required to operate Unit 2 for another two-year cycle.
As a separate matter, as a result of several BWR's 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 is drafting rules which
tentatively require compliance by December 1997. Alternative
resolution options will be subject to NRC approval. PSE&G cannot
predict what other actions, if any, the NRC may take on this matter.
Nuclear Decommissioning
In accordance with Nuclear Waste Policy Act of 1992, as amended
(NWPA), utilities owning an interest in nuclear generating facilities
are required to determine the costs and funding methods necessary to
decommission such facilities upon termination of operation. As a
general practice, each nuclear utility places funds in independent
external trust accounts it maintains to provide for decommissioning.
PSE&G currently recovers from its customers the amounts paid into the
trust fund over a period of years and would continue to do so under its
proposed Alternative Rate Plan (see Note 2 -- Rate Matters of Notes).
For information concerning enrichment of nuclear fuel and nuclear
decommissioning costs, see Note 3 -- PSE&G Nuclear Decommissioning and
Amortization of Nuclear Fuel of Notes.
Electric Fuel Supply and Disposal
The following table indicates PSE&G's KWH output by source of energy:
ACTUAL ESTIMATED
SOURCE 1995 1996
------ ------ ---------
Nuclear
New Jersey facilities.......................... 21% 23%
Pennsylvania facilities........................ 16 15
Fossil
Coal
New Jersey facilities........................... 7 9
Pennsylvania facilities......................... 12 13
Natural Gas..................................... 8 10
Residual Oil.................................... 1 0
Net PJM Interchange and Utility Purchases
and NUGs........................................ 35 30
---- ----
Total................................................. 100% 100%
==== ====
PSE&G's cost of fuel used to generate electricity in the periods shown below
was as follows:
NATURAL
NUCLEAR COAL GAS OIL
--------- ------------------------------------- -------- -------
NEW JERSEY PENNSYLVANIA
FACILITIES FACILITIES
--------------- -------------------
CENTS/ CENTS/ CENTS/ CENTS/ CENTS/
MILLION MILLION MILLION MILLION $/ MILLION
YEAR BTU $/TON BTU $/TON BTU BTU BARREL BTU
- ---- ------ ------- ------- ------- ------- ------- ------ -------
1993 59.3 55.45 203.8 33.73 136.6 221.7 23.44 384.5
1994 62.3 56.31 213.8 34.78 140.7 197.8 22.19 361.02
1995 60.8 58.29 214.0 33.30 134.4 176.6 20.17 324.50
Substantially all of PSE&G's electric sales are made under rates which are
currently designed to permit the recovery of increases in energy costs over base
costs on a current annual basis. The Alternative Rate Plan filed by PSE&G proposes
discontinuing the Levelized Energy Adjustment Clause (LEAC) and NPS and would
substantially shift the risks and opportunities involved in managing changes in fuel
and replacement power costs from customers to PSE&G. (see Note 2 -- Rate Matters of
Notes)
Nuclear Fuel
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 the
uranium hexafluoride gas, conversion of the enriched gas to fuel
pellets and fabrication of fuel assemblies.
PSE&G has several long-term contracts with ore operators to
process uranium ore to uranium concentrate to meet the currently
projected requirements for the Salem and Hope Creek units fully through
the year 2000 and, thereafter, 60% of their requirements through the
year 2002.
Present contracts for conversion, enrichment and fabrication
services to meet the fuel cycle requirements for Salem and Hope Creek
units through the years shown in the following table:
NUCLEAR UNIT CONVERSION ENRICHMENT FABRICATION
- ------------ ---------- ---------- -----------
Salem 1..................... 2000 (1) 2004
Salem 2..................... 2000 (1) 2005
Hope Creek.................. 2000 (1) 2000
(1) 100% coverage through 1998; approximately 50% through 2002; and
approximately 30% through 2004. PSE&G does not anticipate any
difficulties in obtaining necessary enrichment service for its
Salem and Hope Creek units.
PSE&G has been advised by PECO that it has contracts for the
purchase of uranium which will satisfy the fuel requirements of Peach
Bottom 2 and 3 through 2002. PSE&G has also been advised by PECO that
it has contracts for the conversion of uranium concentrates which will
be allocated to Peach Bottom 2 and 3 and two other nuclear generating
units in which PSE&G does not have an interest, on an as-needed basis.
PECO has also advised PSE&G that it has contracted for the
following segments of the nuclear fuel supply cycle for Peach Bottom
2 and 3 through the following years:
NUCLEAR UNIT CONVERSION ENRICHMENT FABRICATION
- ------------ ---------- ---------- -----------
Peach Bottom 2.............. 1997 2008 1999
Peach Bottom 3.............. 1997 2008 1998
For information regarding the decontamination and decommissioning
funds, see Note 3 -- PSE&G Nuclear Decommissioning and Amortization of
Nuclear Fuel of Notes.
Coal
Approximately 40% of PSE&G's coal supply for its New Jersey
facilities is obtained under a contract which expires in 1999. The
balance of the supply is contracted annually from various suppliers,
many of whom PSE&G has dealt with on a continuing basis for a number
of years, and is supplemented by spot market purchases. The New Jersey
Air Pollution Control Code (NJAPCC) permits the burning of coal with
a sulfur content of up to 1% at existing coal-fired generating stations
including PSE&G's three coal-fired New Jersey units, Hudson 2 and
Mercer 1 and 2. The weighted monthly average sulfur content of the
coal received at Hudson Station and at Mercer Station must not exceed
1.0% (dry weight basis). PSE&G has been able to obtain sufficient
quantities of 1% (or less) sulfur coal and does not presently
anticipate any difficulties in obtaining adequate coal supplies to
replace expiring contracts. (See Environmental Controls -- Air
Pollution Control).
PSE&G has approximately a 23% interest in the Keystone and
Conemaugh coal-fired generating stations located in Western
Pennsylvania and operated by Pennsylvania Electric Company. At least
71% of the fuel required by the Keystone station is supplied by one
coal company under a contract which expires December 31, 2004. At least
30% of the fuel required by Conemaugh station is supplied by
another coal company under a contract which expires on December 31,
1997. In addition, approximately 18% of Conemaugh's coal requirements
is supplied by a short-term contract which expires on November 30,
1996. The balance of the fuel requirements for each station is
supplied through spot purchases obtained from local suppliers. The
Keystone Conemaugh Projects Office, which runs project administration
at these plants on a day to day basis, has advised PSE&G that it does
not expect any difficulties in obtaining adequate coal supplies. (See
Environmental Controls).
Natural Gas
PSE&G utilizes natural gas available from various spot, short-term
and long-term gas contracts, to replace other fuels for electric
generation. Presently, there are no effective legal restrictions on
the use of natural gas for electric generation in existing plants.
However, approval by FERC is required for the interstate transportation
of natural gas, either by virtue of existing blanket authority or
through individual proceedings. PSE&G does not expect any difficulties
in obtaining natural gas supplies.
Oil
PSE&G uses residual oil in its conventional fossil-fired,
steam-electric units. The supply of residual oil is furnished by
contract suppliers, supplemented by occasional spot market purchases.
PSE&G uses distillate fuel in its combustion turbines which is acquired
by spot market purchases. PSE&G does not presently anticipate any
difficulties in obtaining oil supplies.
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 NWPA, the Federal government has entered into
contracts for transportation and ultimate disposal of the spent fuel.
The Federal government's present policy is that spent nuclear fuel will
be accepted for long-term storage at government-owned and operated
repositories. However, at present, no such repositories are in service
or under construction. In December 1989, the U.S. Department of Energy
(DOE) announced 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
will be delayed beyond 2010 if sufficient funds are not appropriated
by the Congress for this program.
In conformity with the NWPA, PSE&G entered into contracts with the
DOE for the disposal of spent nuclear fuel from Salem and Hope Creek.
Similarly, PECO contracted with the DOE in connection with Peach Bottom
2 and 3. Under these contracts, the DOE is required to take title to
the spent fuel at the site, then transport it and provide for its
permanent disposal at a cost of one mil per KWH of nuclear generation,
subject to such escalation as may be required to assure full cost
recovery by the Federal government. In addition, a one-time payment was
made to the DOE for permanently discharged spent fuels irradiated prior
to 1983.
On April 28, 1995, the DOE published its final interpretation on
the nuclear waste acceptance issues in which it stated that it had no
legal obligation to begin waste acceptance in 1998, in the absence of
a repository or other storage facility. PSE&G s contracts with DOE
call for DOE to begin accepting spent fuel from PSE&G in 1998. As a
result, on September 7, 1995, PSE&G, along with 24 other utilities and
a combination of 48 States, state regulatory agencies and municipal
power agencies, filed a lawsuit in the US District Court of Appeals for
the District of Columbia Circuit against the DOE to protect its
contractual rights.
Pursuant to NRC rules, spent nuclear fuel generated in any reactor
can be stored safely and without significant environmental impact in
reactor facility storage pools or in independent spent fuel storage
installations located at reactor or away-from-reactor sites for at
least 30 years beyond the licensed life for reactor operation (which
may include the term of a revised or renewed license).
As a result of reracking the two spent fuel pools at Salem, the
availability of adequate spent fuel storage capacity is conservatively
estimated through 2008 for Salem 1 and 2012 for Salem 2, 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. The units can be safely operated for many years
beyond these dates, as pool storage capacity will continue to be
available. These dates simply assist in planning the need for
additional storage capacity that may be needed to operate the units
until the expiration of their operating license. In addition, PECO has
advised PSE&G that spent fuel racks at Peach Bottom have storage
capacity until 2000 for Unit 2 and 2001 for Unit 3, prior to losing
full core reserve capability, and that expansion of storage capacity
beyond such dates is being investigated.
Low Level Radioactive Waste (LLRW)
As a by-product of their operations, nuclear generating units,
including those in which PSE&G owns an interest, produce LLRW. Such
wastes include paper, plastics, protective clothing, water purification
materials and other materials. Such materials are accumulated on site
and disposed of at a federally licensed permanent disposal facility in
Barnwell, South Carolina.
In 1991, New Jersey enacted legislation providing for funding of
the estimated $90 million cost of establishing a LLRW disposal
facility. The State would recover the costs through fees paid by LLRW
generators. PSE&G's overall share is expected to be about 40% of the
total cost and has provided about $4.8 million to date. New Jersey has
introduced a volunteer siting process to establish a LLRW disposal
facility by the year 2000. Public meetings have been held across the
state in an effort to provide information to and obtain feedback from
the public. To date, there have been no volunteers identified.
Because of the uncertainties in disposal, PSE&G built an on-site
facility completed in September 1994. This facility provides five
years storage for LLRW from Hope Creek and Salem. The facility was used
from July 1994 through June 1995, while the Barnwell facility was
temporarily unavailable, and emptied when Barnwell re-opened in 1995.
It will be used for interim storage of radioactive materials and waste,
and if it proves necessary in the future, to temporarily store waste
until New Jersey provides a permanent disposal facility.
PECO has advised PSE&G that it has an on-site LLRW storage
facility for Peach Bottom, which will provide at least 5 years of
temporary storage. PECO has also advised PSE&G that Pennsylvania is
pursuing its own LLRW site development via state-selected candidate
sites, along with a volunteer plan option. PSE&G has paid $2.5 million
as its share of siting costs due to its ownership in the Peach Bottom
units.
Gas Operations and Supply
PSE&G supplies its gas customers principally with natural gas.
PSE&G supplements natural gas with purchased refinery gas and liquefied
petroleum gas produced from propane. The adequacy of supply of all
types of gas is affected by the nationwide availability of all sources
for energy production.
As of December 31, 1995, the daily gas capacity of PSE&G was as
follows:
Type of Gas Therms Per Day
------------------------------------ --------------
Natural gas......................... 23,191,270
Liquefied petroleum gas............. 2,200,000
Refinery gas........................ 400,000
-----------
Total........................... 25,791,270
===========
About 40% of the daily gas capacity is high load factor natural
gas and is available every day of the year. The remainder comes from
field storage, liquefied natural gas, seasonal sales, contract peaking
supply, propane and refinery gas.
PSE&G's total gas sold to and transported for its various customer
classes in 1995 was 3.9 billion therms which consisted of approximately
96% natural gas. Included in this amount is 1.6 billion therms of gas
delivered to customers under PSE&G's transportation tariffs and
individual cogeneration contracts. (See Operating Statistics of PSE&G).
During 1995, PSE&G purchased approximately 3.3 billion therms of gas
for its combined gas and electric operations directly from natural gas
producers and marketers and the balance from interstate pipeline
suppliers. These supplies were transported to New Jersey by PSE&G's
four interstate pipeline suppliers. This diversification of supply
sources provides PSE&G with reliability of supply, purchasing
flexibility and lower overall costs.
PSE&G's gas supply contracts expire at various times over the next
two to ten years. PSE&G does not presently anticipate any difficulty
in negotiating replacement contracts. Since the quantities of gas
available to PSE&G under its supply contracts are more than adequate
in warm months, PSE&G nominates part of such quantities for storage,
to be withdrawn during the winter season, under storage contracts with
its principal suppliers. Underground storage capacity currently is
approximately 770 million therms. PSE&G does not presently anticipate
any difficulty in obtaining adequate supplies of natural gas.
PSE&G's annual average cost of natural gas sendout is shown below:
Cents Per
Year Million BTU(A)
---------------------------------- --------------
1995.............................. 308.00
1994.............................. 318.09
1993.............................. 327.00
(A) Excludes contribution by PSE&G's electric operating units for a
gas reservation charge and natural gas refunds from suppliers.
Substantially all of PSE&G's gas sales are made under rates which
are currently designed to permit the recovery of projected increases
in the cost of natural gas and gas from supplemental sources, when
compared to levels included in base rates, on a current annual basis.
(See Note 2 -- Rate Matters of Notes.)
The demand for gas by PSE&G's customers is affected by customer
conservation, economic conditions, weather, the price relationship
between gas and alternative fuels and other factors not within PSE&G's
control. Presently, the majority of gas sold in interstate commerce has
become deregulated. The ability of gas prices to respond to market
conditions has improved in recent years because of actions taken by the
FERC. Pipeline companies are able to adjust their gas rates up or down
through their purchased gas adjustment mechanism more often than the
semi-annual filings of prior years. As discussed above in Competition,
FERC actions provided pipeline customers, such as PSE&G, with the
opportunity to convert a portion of their pipeline sales contracts to
transportation agreements and purchase natural gas supplies directly
from a producer or other seller of natural gas. This has increased
competition in the gas market by encouraging pipeline companies to act
as non-discriminatory transporters of natural gas. PSE&G has taken
advantage of these actions to lower its overall gas costs through the
displacement of higher cost contract supplies with lower cost spot gas
purchases and long-term producer contract supplies. (See Competition.)
PSE&G was able to meet all of the demands of its firm customers
during the 1994-95 winter season and expects to continue to meet such
energy-related demands of its firm customers during the 1995-96 winter
season. However, the sufficiency of supply could be affected by several
factors not within PSE&G's control, including curtailments of natural
gas by its suppliers, the severity of the winter, the extent of energy
conservation by its customers and the availability of feedstocks for
the production of supplements to its natural gas supply. During the
1995-96 heating season through February 14, 1996, it was necessary for
PSE&G to interrupt service to 'interruptible' customers for 25 days as
permitted by the applicable tariff. During the 1994-95 heating season,
service to such customers was interrupted for eight days.
Employee Relations
Enterprise has no employees. As of December 31, 1995, PSE&G and
its subsidiaries employed 11,452 persons. Four-year bargaining
agreements between PSE&G and its unions, representing 6,746 employees,
will expire April 30, 1996. Also at December 31, 1995, EDHI and its
subsidiaries employed 523 persons, of which 38 were represented by
unions. PSE&G, EDHI and their subsidiaries believe that they maintain
satisfactory relationships with their employees.
For information concerning the employee pension plan and other
postretirement benefits, see Note 1 -- Organization and Summary of
Significant Accounting Policies, Note 13 -- Postretirement Benefits
Other Than Pensions and Note 14 -- Pension Plan of Notes.
Regulation
Enterprise has claimed an exemption from regulation by the SEC as
a registered holding company under PUHCA, except for Section 9(a)(2)
thereof, which relates to the acquisition of 5% or more of the voting
securities of an electric or gas utility company. Enterprise is not
subject to direct regulation by the BPU, except potentially with
respect to certain transfers of control and reporting requirements, and
is not subject to regulation by the FERC. The BPU may also impose
certain requirements with respect to affiliate transactions between and
among PSE&G, Enterprise and Enterprise's nonutility subsidiaries. (See
EDHI.)
As a New Jersey public utility, PSE&G is subject to comprehensive
regulation by the BPU including, among other matters, regulation of
intrastate rates and service and the issuance and sale of securities.
As a participant in the ownership and operation of certain generation
and transmission facilities in Pennsylvania, PSE&G is subject to
regulation by the Pennsylvania Public Utility Commission (PPUC) in
limited respects in regard to such facilities.
PSE&G is subject to regulation by FERC and by the Economic
Regulatory Administration, both within DOE, with respect to certain
matters, including regulation by FERC with respect to interstate sales
and exchanges of electric transmission, capacity and energy, including
cogeneration and small power production projects being constructed
pursuant to PURPA, and accounts, records and reports. PSE&G is also
subject to regulation by the United States Department of Transportation
(USDOT) with respect to safety standards for pipeline facilities and
the transportation of gas under the Natural Gas Pipeline Safety Act of
1968.
In addition, the New Jersey Need Assessment Act (NJNAA) provides
that no public utility shall commence construction of any electric
facility (as defined in the NJNAA) without having first obtained a
Certificate of Need (Certificate of Need) from the Division of Energy
Planning and Conservation within the New Jersey Department of
Environmental Protection (NJDEP). A Certificate of Need, if granted,
is valid for three years, renewable subject to review by the
Commissioner of the NJDEP. Under the NJNAA, no state or local agency
may issue any license or permit required for any such construction or
substantial expansion prior to the issuance of the Certificate of Need.
An electric facility is defined under the NJNAA as any electric power
generating unit or combination of units at a single site with a
capacity of 100 MW or more or any such units added to an existing
electric generating facility which will increase its installed capacity
by 25% or by more than 100 MW, whichever is smaller. Under NJNAA, a
Certificate of Need will be issued only if the NJDEP Commissioner
determines that the proposed facility is necessary to meet the
projected need for electricity in the area to be served and that no
more efficient, economical or environmentally sound alternative is
available.
For information concerning nuclear insurance coverages, the BPU's
NPS and assessments and the Price-Anderson Amendments Act of 1988, as
amended, (Price Anderson) see Note 12 -- Commitments and Contingent
Liabilities of Notes.
The New Jersey Public Utility Accident Fault Determination Act
(Fault Act) requires the BPU to make a determination of fault with
regard to any accident at any electric generating or transmission
facility prior to granting a request by any utility for a rate increase
to cover accident-related costs in excess of $10 million. Fault, as
defined in the Fault Act, means any negligent action or omission of any
party which either contributed substantially to causing the accident
or failed to mitigate its severity.
However, the Fault Act 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 and allows the BPU to authorize the
recovery of certain fault-related repair, clean-up, power replacement
and damage costs if substantiated by the evidence presented and if
authorized in writing by the BPU. The Fault Act could have a material
adverse effect on PSE&G's financial position if such an accident were
to occur at a PSE&G facility, it was ultimately determined that the
accident was due to the fault of PSE&G and the BPU were to deny
recovery of all or a portion of the costs related thereto. The
Alternative Rate Plan filed by PSE&G proposes discontinuing LEAC and
NPS and would substantially shift the risks and opportunities involved
in managing changes in fuel and replacement power costs from customers
to PSE&G. See Note 2 - Rate Matters -- Alternative Rate Plan and LEAC
of Notes.
Under New Jersey law, the BPU is required to audit all or a
portion of the operating procedures and other internal workings of
every gas or electric utility subject to its jurisdiction, including
PSE&G, at least once every six years. Under the law, the audit may be
performed either by the BPU Staff or under the supervision of
designated members of such Staff by an independent management
consulting firm, chosen by the utility from a list provided by the BPU.
The BPU may, upon completion of the audit and after notice and hearing,
order the utility to adopt such new practices and procedures that it
shall find reasonable and necessary to promote efficient and adequate
service to meet public convenience and necessity. The last such
management audit of PSE&G was completed in 1991.
In 1992, as a follow-up to its 1991 management audit, the BPU
conducted a focused audit of Enterprise's nonutility businesses to
ascertain whether nonutility activities had harmed PSE&G. Enterprise
has consistently maintained a clear and distinct separation of its
utility and nonutility operations and believes that its nonutility
activities have not in any way adversely affected the utility. The
results of the focused audit confirmed that there has been no harm to
PSE&G as a result of Enterprise's nonutility activities. However, as
a result of recommendations made by the BPU's auditors regarding
operations and intercompany relationships between PSE&G and EDHI's
nonutility businesses, the BPU approved a plan which, among other
things, provides: (1) that Enterprise will not permit EDHI's nonutility
investments to exceed 20% of Enterprise's consolidated assets without
prior notice to the BPU (such assets at December 31, 1995 were
approximately 15%); (2) for a restructuring of the PSE&G Board to
include nonemployee Enterprise directors with an annual certification
by such Board that the business and financing plans of EDHI will not
adversely affect PSE&G; (3) for an Enterprise agreement to (a) limit
debt supported by the minimum net worth maintenance agreement between
Enterprise and Capital to $750 million, and (b) make a good-faith
effort to eliminate such support over a six to ten year period from
April 1993; and (4) the payment by EDHI to PSE&G of an affiliation fee
of up to $2 million a year which will be applied by PSE&G through its
LGAC and LEAC to reduce utility rates. Effective January 31, 1995, the
debt supported by the minimum net worth maintenance agreement will be
limited to $650 million and such affiliation fee will be
proportionately reduced as such supported debt is reduced. In
addition, Enterprise and EDHI and its subsidiaries continue to
reimburse PSE&G for all costs of services provided by employees of
PSE&G.
The issue of Enterprise sharing the benefits of consolidated tax
savings with PSE&G or its ratepayers was not resolved by the plan
approved as a result of the focused audit and remains open. Enterprise
believes that PSE&G's taxes should be treated on a stand-alone basis
for rate-making purposes, based on the separate nature of the utility
and nonutility businesses. However, neither Enterprise nor PSE&G is
able to predict what action, if any, the BPU may take concerning
consolidation of tax benefits in future proceedings. On July 28, 1995,
the BPU reported to PSE&G that it had fully evaluated all available
information regarding the 18 recommendations of the Focused Audit
conducted by the BPU's consultant and determined that 17 have been
implemented pursuant to the BPU's Order Approving Audit Implementation
Plans. The remaining issue regarding Enterprise sharing the benefits
of consolidated taxes with PSE&G or its ratepayers may be considered
in the context of a future base rate case, or in a filing that
considers an alternative form of regulation. PSE&G cannot predict what
actions, if any, the BPU may take regarding the consolidated tax issue.
(See Note 2 -- Rate Matters - Consolidated Tax Benefits of Notes.)
Construction and operation of nuclear generating facilities are
regulated by the NRC. For additional information relating to regulation
by the NRC, see Nuclear Operations. In addition, the Federal Emergency
Management Agency is responsible for the review in conjunction with the
NRC of certain aspects of emergency planning relating to the operation
of nuclear plants.
CEA invests in and participates in the development and operation
of domestic and foreign cogeneration and power production facilities,
which include QFs and EWGs. For additional information, see EDHI --
CEA.
The BPU has authority to regulate power sales agreements within
the BPU's pricing guidelines to utilities in the State of New Jersey
and ascertain that the terms and conditions of agreements with New
Jersey utilities are fair and reasonable. For additional information,
see EDHI.
Environmental Controls
PSE&G, like most industrial enterprises, is subject to regulation
with respect to the environmental impacts of its operations, including
air and water quality control, limitations on land use, disposal of
wastes, aesthetics and other matters, by various federal, regional,
state and local authorities, including the United States Environmental
Protection Agency (EPA), the United States Department of Transportation
(USDOT), NJDEP, the New Jersey Department of Health, the BPU, the
Interstate Sanitation Commission, the Hackensack Meadowlands
Development Commission, the Pinelands Commission, the Delaware River
Basin Commission, the United States Coast Guard and the United States
Army Corps of Engineers. EDC, CEA and EGDC are also subject to similar
regulation with respect to operation of their facilities. (See EDHI)
Environmental laws generally require air emissions and water
discharges to meet specified limits. They also impose potential joint
and several liability, without regard to fault, on the generators of
various hazardous substances to manage these materials properly and to
clean up property affected by the production and discharge of such
substances. Compliance with environmental requirements has caused
PSE&G to modify the day-to-day operation of its facilities, to
participate in the cleanup of various properties that have been
contaminated and to modify, supplement and replace existing equipment
and facilities. During 1995, PSE&G expended approximately $148 million
for capital related expenditures to improve the environment and comply
with changing regulations. It is estimated that PSE&G will expend
approximately $81 million, $43 million, $35 million, $30 million and
$13 million in the years 1996 through 2000, respectively, for such
purposes. Such amounts are included in PSE&G's estimates of
construction expenditures. (See MD&A -- Liquidity and Capital
Resources.)
Preconstruction analyses and projections of the environmental
impacts of contemplated activities, discharges and emissions are
frequently required by the permitting agency. Before licensing
approvals and permits are granted, the agency usually requests a
modeling analysis of the effects of a specific action, and of its
effect in combination with other existing and permitted activities, and
may request the applicant to address emerging environmental issues.
Such environmental reviews have caused delays in the proceedings for
licensing facilities and similar delays can be expected in the future.
An industry issue with respect to the construction and operation
of electric transmission and distribution lines is the alleged adverse
health effects of EMF exposure. In 1990, the New Jersey Commission on
Radiation Protection (CORP) decided against setting a limit on magnetic
fields produced by high-voltage power lines citing the lack of
convincing evidence required to determine dangerous levels. Proposed
power regulations are currently under study by CORP to cover new power
lines and allow existing power lines to continue to function regardless
of new rule changes. If revised, the rules would authorize the NJDEP
to screen all new power line projects of 100 kilovolts or more using
a principle of "as low as reasonably achievable" to demonstrate that
all steps within reason, including modest cost, were taken to reduce
EMFs. The outcome of EMF study and/or regulations and the public
concerns will affect PSE&G's design and location of future electric
power lines and facilities and the cost thereof. Such amounts as may
be necessary to comply with these new EMF rules and address public
concerns cannot be determined at this time, but such amounts could be
material.
The New Jersey Environmental Rights Act provides that any person
may maintain a court action against any other person to enforce, or to
restrain the violation of any statute, regulation or ordinance which
is designed to prevent or minimize pollution, impairment or destruction
of the environment, or where no such violation exists, to protect the
environment from pollution, impairment or destruction. Certain Federal
legislation confers similar rights on individuals. The principal laws
and regulations relating to the protection of the environment which
affect PSE&G's operations are described below.
Air Pollution Control
The Federal Clean Air Act ("CAA") imposes emission control
requirements across the United States, including requirements related
to the emissions of sulfur dioxide and Nitrogen Oxides ("NOx") and
requires attainment of National Ambient Air Quality Standards
("NAAQS").
PSE&G's two wholly-owned and operated coal-fired generating
stations in New Jersey are presently expected to be able to meet CAA
sulfur dioxide requirements with only modest expenditures.
PSE&G also has approximately a 23% interest in Conemaugh and
Keystone, coal-fired generating stations located in western
Pennsylvania. With respect to Conemaugh, in order to comply with the
CAA Sulfur Dioxide Requirements, the station's co-owners, including
PSE&G, approved the installation of scrubbers (flue gas desulfurization
systems). PSE&G's share of the remaining Conemaugh scrubber cost is
less than $1.0 million and is included in PSE&G's estimate of
construction expenditures. Scrubber construction at Conemaugh Unit 2
was completed in November 1995. Keystone is presently expected to
comply with the Sulfur Dioxide Requirements by utilizing excess
emission allowances from the over-scrubbing of the Conemaugh units.
The CAA established a national emission trading system for Sulfur
Dioxide allowances. Yearly allowances have been allocated according
to a formula specified by the CAA and applicable to owner/operators of
large boilers and power generating equipment.
New Jersey and other Northeastern states have imposed Reasonably
Available Control Technology ("RACT") requirements on each major source
of NOx. Additionally, these states have committed to additional
overall NOx emission reductions on power plants and large industrial
boilers of .2 pounds per million BTUs by 1999 with potential additional
reductions of .15 pounds per million BTUs by 2003. All of PSE&G's
Fossil Generating units are currently in compliance with RACT
requirements.
The NJDEP, in concert with other states in the Northeast, is
implementing a regional CAA NOx allowance emission trading system for
power plants and large industrial boilers. This includes the
allocation of emission allowances to these sources in 1996. The NOx
allowance trading system is scheduled to be operational by the
beginning of 1999 and could result in additional changes to equipment,
methods of operation or fuel.
EPA has promulgated six NAAQS. PSE&G's Fossil Generating Stations
are all located in areas of non-attainment for ozone. Each state has
the responsibility under the CAA to adopt a plan, and regulations, to
attain and maintain compliance to these standards.
In New Jersey, NJDEP is using the New Jersey Air Pollution Control
Code ("NJAPCC") to achieve compliance with, and maintenance of, the
NAAQS. The NJAPCC provides stringent requirements restricting the
sulfur content in coal and oil fuels. (See PSE&G -- Electric Fuel
Supply and Disposal -- Coal.) The increased cost of purchasing low-
sulfur fuel is offset by rates which are designed to permit the
recovery of fuel costs on a current annual basis. In accordance with
the proposed Alternative Rate Plan, separate mechanisms would be
established to ensure continued recovery of costs associated with
activities mandated or approved by state or federal agencies or
otherwise out of PSE&G's control. (See PSE&G -- Electric Fuel Supply
and Disposal and Note 2 -- Rate Matters of Notes.)
The CAA also requires that each major facility apply for and
receive a facility-wide operating permit. The facility-wide operating
permit terms and conditions are enforceable by both the EPA and NJDEP.
PSE&G filed permit applications for its major facilities in New Jersey
in 1995. The operating permit program will require some PSE&G
facilities to assess emissions, which could require the installation
of emission monitoring equipment and changes to facility operations or
technology. To the extent estimates of the costs of complying with
these requirements through the year 2000 are quantifiable, they are
included in PSE&G's construction expenditures. In accordance with the
filed Alternative Rate Plan, PSE&G has requested to have separate
mechanisms to ensure continued recovery of costs associated with
activities mandated or approved by State or Federal agencies, although
no assurances can be given as to what action may be taken by the BPU.
In addition, the revised CAA requirements will increase the cost of
producing electricity for the Pennsylvania and Ohio Valley Region
Generating units supplying electricity to the PJM and New Jersey. All
of PSE&G's current purchased power costs are included in PSE&G's LEAC.
(See Note 2 -- Rate Matters of Notes.)
In non-attainment areas, one of the effects of the CAA is to allow
construction or expansion of a facility only upon a showing that any
additional emissions from the source will be more than offset by
reductions in similar emissions from existing sources. In prevention
of significant deterioration areas, construction or expansion of a
facility would be permitted only if emissions from the source, together
with emissions from other expected new sources, would not violate air
quality increments for particulates and sulfur dioxide that are more
stringent than NAAQS. All of these requirements may affect PSE&G's
ability to locate, construct or expand generating facilities in the
future.
PSE&G has been working collaboratively with environmentalists, a
select number of other electric utilities in the Northeast, NJDEP and
other Northeast environmental regulators, EPA, and a number of large
manufacturing companies to achieve significant emission reductions from
power plants in the Midwest. PSE&G has also been working with these
respective groups to establish a flexible NOx and Volatile Organic
Compound ("VOC") emissions trading system as a compliance alternative
to CAA compliance requirements for industrial facilities, highway and
off-highway emission sources, state transportation CAA conformity and
automobile inspection and maintenance. Significant emission reductions
from Midwest are expected to improve New Jersey's and the Northeast's
air quality thereby lessening the need for additional New Jersey
emission controls over and beyond those already regulatorily adopted.
These collaborative efforts, coupled with growing environmental
regulator and industry concerns for cost-effective compliance with CAA
requirements, have resulted in the creation of a thirty-seven state
environment forum called Ozone Transport Assessment Group ("OTAG").
This includes Midwest, Northeast and Southern states east of the
Mississippi River. OTAG's charter is to produce consensus
recommendations concerning the need for additional emission controls
and to identify the level and sources to which those controls should
be applied. OTAG is expected to conclude its work by the fall of 1996.
If the OTAG process fails to produce consensus that leads to an
agreement by individual states to undertake timely necessary control
actions, affected downwind states such as those in the Northeast are
required as part of their EPA approved 1994 CAA State Implementation
Plans to submit petitions to EPA seeking EPA's imposition of controls
on upwind states. It is difficult to determine at this time the likely
outcome of this process.
Recently, the issue of transported air pollution from the Midwest
power plants and their negative impact on air quality in the Northeast
has become the subject of concern before the FERC. The FERC has
performed a draft environmental impact statement to assess the
environmental impact of developing a generic rule by which electric
utilities will be required to provide full non-discriminatory
transmission access to all wholesale power providers. PSE&G and a
number of other utilities, environmental groups and regulators have
submitted comments seeking FERC's mitigation of expected additional
power plant emissions resulting from the implementation of FERC's open
access policies. It is too soon to determine to what extent FERC will
act on the concerns raised.
Water Pollution Control
The Federal Water Pollution Control Act (FWPCA) authorizes the
imposition of technology and water-quality based effluent limitations
to regulate the discharge of pollutants into the surface waters of the
United States through the issuance of National Pollutant Discharge
Elimination System (NPDES) permits. The New Jersey Water Pollution
Control Act (NJWPCA) authorizes the NJDEP to regulate discharges to
surface waters and ground waters of the State through the New Jersey
Pollutant Discharge Elimination System (NJPDES) permits. NJDEP also
administers the NPDES/NJPDES permit program. Certain PSE&G facilities
are directly regulated by NJPDES permits issued pursuant to FWPCA and
the NJWPCA.
In addition, the FWPCA also imposes additional requirements with
respect to the control of toxic discharges to degraded waterbodies
under Section 304(1). Although five PSE&G electric generating stations
(Bergen, Hudson, Kearny, Linden and Sewaren) were originally subject
to requirements imposed pursuant to Section 304(l), the NJDEP and EPA
have proposed delisting these stations from the 304(l) program for the
present time.
The FWPCA also authorizes the imposition of less stringent thermal
limits pursuant to a variance procedure set forth in Section 316(a) and
the regulation of cooling water intake structures pursuant to Section
316(b). PSE&G has filed information with the NJDEP in support of
Section 316(a) variance requests and Section 316(b) best technology
available determinations for several of its electric generating
stations which are pending before the NJDEP presently and may be
required to submit information for other stations as a result of the
permit renewal process. With respect to Section 316(b) requirements,
the EPA initiated a rulemaking procedure in 1994 to develop regulations
implementing this provision. Pursuant to a Consent Decree entered by
a Federal District Court resolving an action to compel the rulemaking
brought by a number of environmental groups including certain of those
who opposed the 1994 Salem NJPDES permit, EPA must propose draft
regulations on or before July 2, 1999 and promulgate final regulations
by August 2001. While the content and scope of these regulations can
not be predicted at this time, they may have a considerable effect on
agency review of section 316(b) determinations pending in 1999 or
after. (see discussions on Hudson, Mercer, and Salem NJPDES permits
below.)
The FWPCA and the NJWPCA also authorize the discharge of
stormwater from certain facilities including steam electric generating
stations. In many instances, this is accomplished through the
development of Stormwater Pollution Prevention Plans (SPPP).
Similarly, both laws authorize Publicly Owned Treatment Works (POTW)
to issue permits for significant industrial users (SIU) of the
treatment facility. Certain of PSE&G's facilities have permits under
the SPPP and SIU programs.
A brief discussion on pending permit proceedings which have the
potential to impose new or more stringent terms or conditions which
could require changes to operations or significant expenditures
follows:
Hudson Station's NJPDES permit is in the process of being renewed
by the NJDEP. As part of that renewal, the NJDEP has requested updated
information in connection with PSE&G's 316(a) and 316(b)
demonstrations, in part, to address issues identified by a consultant
hired by NJDEP. The consultant recommended that Hudson be retrofit to
operate with closed cycle cooling to address alleged adverse impacts
associated with the thermal discharge and intake structure. PSE&G is
in the process of collecting additional data which will be used in the
updated demonstrations. PSE&G anticipates submitting these documents
to NJDEP in the first quarter of 1998. It is impossible to predict the
NJDEP's determinations on these demonstrations; however, PSE&G
presently estimates that the cost of retrofitting Hudson to operate
with closed cycle cooling could be in excess of $59 million in 1998
dollars.
NJDEP has advised PSE&G that it is preparing a renewal permit for
Mercer Station and, in connection with that renewal, will also be
reexamining Mercer's compliance with Section 316(a) & 316(b). This may
result in PSE&G's being required to submit updated 316(a) and 316(b)
demonstrations for NJDEP review. It is impossible to predict at this
time the outcome of such review.
PSE&G is implementing the 1994 NJPDES permit issued for Salem
Station which requires, among other things, water intake screen
modifications and wetlands restoration. In addition, PSE&G is seeking
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. The estimated
capital cost of compliance with the final permit is approximately $100
million, of which PSE&G's share is 42.59% and is included in PSE&G's
1996-2000 construction program. In accordance with the filed
Alternative Rate Plan PSE&G has requested to have separate mechanisms
to ensure continued recovery of costs associated with activities
mandated or approved by State or Federal agencies, although no
assurances can be given as to what action may be taken by the BPU.
PSE&G must apply to renew the Salem permit in March 1999 which renewal
application must provide updated Section 316(a) and 316(b)
demonstrations for the NJDEP's review. (See the discussion above
regarding EPA's Section 316(b) rulemaking.) (See MD&A -- Liquidity and
Capital Resources -- Construction, Investments and Other Capital
Requirements Forecast.)
In June, 1995, PSE&G filed an application with the Delaware River
Basin Commission (DRBC) seeking a modification to the heat dissipation
area previously established based upon the NJDEP's grant of a Section
316(a) variance for Salem Station. DRBC issued a modified Docket in
September 1995 granting PSE&G's request. PSE&G must reapply to the DRBC
in 1999 for a continuation of this heat dissipation area.
PSE&G anticipates that NJDEP will issue a draft renewal permit for
Hope Creek Station in 1996 which will not propose effluent limitations
or other requirements significantly more stringent than those in the
existing permit.
CEA Eagle Point, Inc. (Eagle Point), an indirect subsidiary of
CEA, is a partner in a partnership which owns the Eagle Point
Cogeneration Facility (EPC), located in West Deptford, New Jersey. EPC
is operated by an affiliate of Eagle Point's partner and provides
electricity and steam for an adjacent petroleum refinery (owned and
operated by another affiliate of Eagle Point's partner) and sells
excess electricity to PSE&G. On January 15, 1995, Eagle Point received
a Notice of Violation (NOV) from Region II of EPA alleging violations
of certain CAA requirements and limitations related to the air permit
at EPC and the adjacent refinery and demanding that such violations be
corrected. Eagle Point, its partner and the operator of the refinery
are contesting the EPA conclusion that violations have occurred and
have met with staff of EPA and NJDEP to discuss issues related to the
NOV. Eagle Point cannot predict whether EPA will take action with
respect to the NOV and, if so, what action it may take. Applicable
regulations provide EPA with the power to seek to collect criminal and
civil penalties for continued violation of the provisions of air
permits.
Control of Hazardous Substances
PSE&G Manufactured Gas Plant Remediation Program
For information regarding PSE&G's Manufactured Gas Plant
Remediation Program, see Note 12 -- Commitments and Contingent
Liabilities of Notes.
Other Sites
A preliminary review of possible mercury contamination at the
Kearny Station concluded that an additional study and investigations
are required. In 1995, PSE&G entered into a Memorandum of Agreement
(MOA) with NJDEP for the Kearny Generating Station pursuant to which
PSE&G will conduct a Remedial Investigation (RI) of the site. A
Remedial Investigation Work Plan (RIWP) has been filed and is currently
under review by the NJDEP. Field work activities associated with the
RI will begin after NJDEP approval of the RIWP.
Hazardous Substances
The Federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 (CERCLA), as amended by the Superfund Amendments
and Reauthorization Act of 1986 and the Federal Resource Conservation
and Recovery Act of 1976 (RCRA), authorize EPA to issue orders and/or
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 NJDEP. Because of the nature
of PSE&G's business, including the production of electricity, the
distribution of gas and, formerly, the manufacture of gas, various
by-products and substances are or were produced or handled which
contain constituents classified as hazardous under one or more of the
above laws.
PSE&G generally provides for the disposal or processing of such
substances through licensed independent contractors. However, these
statutory provisions impose joint and several liability without regard
to fault on all allegedly responsible parties, including the generators
of the hazardous substances for certain investigative and cleanup
costs at sites where these substances were disposed or processed. These
statutes also authorize private rights of action for recovery of these
costs.
PSE&G has been notified with respect to a number of such sites
and the cleanup of these potentially hazardous sites is receiving
greater attention from the government agencies involved.
Generally,actions directed at funding such site investigations and
cleanups include suspected or known allegedly responsible parties.
PSE&G's past operations suggest that some remedial action may be
required. PSE&G does not expect its expenditures for any such site to
have a material effect on its financial position, results of operations
or net cash flows.
EPA has determined that a portion of the Passaic River from a
point at its confluence with Hackensack River to a point six miles up-
river (the Site) is a "facility" within the meaning of that term as
defined under CERCLA. EPA has also determined that five corporations
are persons within the meaning of CERCLA for purposes of liability
under CERCLA with respect to remedial actions at the Site. EPA has
publicly indicated that it is continuing an assessment of available
information with respect to the identification of other responsible
parties. One of these corporations has entered into a consent order
with EPA pursuant to which it is obligated to conduct a remedial
investigation, human and ecological risk assessment and feasibility
study relating to the Site. Field work activities associated with
these actions were initiated in the spring of 1995. A report
presenting the results of the remedial investigation and risk
assessment is scheduled to be filed in the fall of 1997.
PSE&G and certain of its predecessors conducted operations at
properties along the Passaic River both within and outside the Site.
EPA has not named PSE&G as a responsible party. PSE&G cannot predict
what, if any, action EPA or others may take against PSE&G with respect
to the Site or, in such event, what contributions PSE&G may be required
to make to the costs of these initiatives.
Presently, significant CERCLA/Spill Act actions involving PSE&G
include the following:
(1) Claim made in 1985 by U. S. Department of the Interior under
CERCLA with respect to the Pennsylvania Avenue and Fountain Avenue
municipal landfills in Brooklyn, New York for damages to natural
resources. The U.S. Government alleges damages of approximately $200
million. To PSE&G's knowledge, there has been no action on this matter
since 1988.
(2) Claim by EPA, Region III, under CERCLA with respect to a site
operated by Sealand Ltd. in Mount Pleasant Township, New Castle County,
Delaware. PSE&G and other companies have entered into an Administrative
Consent Order (ACO) obligating the signatories thereto to fund a
Remedial Investigation and Feasibility Study (RI/FS). PSE&G's share
of the costs of actions taken at this site have approximated 25% of
such costs. In 1991, EPA entered a Record of Decision (ROD) which
determined that no further action was required at the site. The State
of Delaware filed comments objecting to this ROD and hired a consultant
which has recommended that additional actions be taken at the site
based on its review of EPA's files. The State of Delaware required the
potentially responsible parties (PRPs) to conduct additional
groundwater analyses during 1994. Based on its review of the
monitoring data, in 1995, the State of Delaware proposed to require the
PRPs to conduct additional groundwater monitoring for a five year
period and to reimburse it for its past and future oversight costs
associated with this site. Delaware has not yet provided an estimate
on its oversight costs.
(3) At the Duane Marine Salvage Corporation Superfund Site in
Perth Amboy, Middlesex County, New Jersey, PRPs including PSE&G, had
completed an EPA-approved surface removal action during 1986 and EPA
had required no further response actions. However, NJDEP ordered that
an RI/FS be performed to address or disprove an alleged subsurface
contamination and, following negotiations with the PRPs, including
PSE&G, an ACO was executed. The PRPs have submitted an RI/FS and a
second revised Draft Feasibility Study. In 1994, NJDEP selected a
remedy for the site, the total cost of which is estimated to be
$1,500,000. Based upon the claims made and activities taken to date,
PSE&G anticipates that its obligations with respect to this site will
be de minimis.
(4) Spill Act Directive issued by NJDEP in 1987 to PRPs, including
PSE&G, with respect to a site formerly owned and operated by Borne
Chemical Company in Elizabeth, Union County, New Jersey, ordering
certain interim actions directed at both site security and the off-site
removal of certain hazardous substances. Certain PRPs, including PSE&G,
signed an ACO with NJDEP to secure the site, which has been completed.
After further negotiations, certain other PRPs, including PSE&G, signed
a further ACO requiring them to perform a removal action at the site,
which was completed in 1992. In 1994, NJDEP issued a third Directive
requiring the performance of an RI/FS. Following negotiations with
certain PRPs including PSE&G, an MOA regarding the conduct of the RI/FS
was executed in 1995. Based upon the claims made and activities taken
to date, PSE&G anticipates that its obligations with respect to this
site will be de minimis.
(5) A second Directive pursuant to the Spill Act was issued by
NJDEP in 1989 to PRPs, including PSE&G, with respect to the PJP
Landfill in Jersey City, Hudson County, New Jersey (PJP), ordering
payment of operating and maintenance costs of approximately $150,000
and reasserting claims made in an initial Directive for all past and
future costs associated with investigations and remediation of the
alleged contamination. Additionally, in 1990, also pursuant to the
Spill Act, NJDEP issued a Multi-Site Directive concerning four sites,
including PJP. With respect to the PJP site, NJDEP reasserted demands
for payment made in earlier Directives. The NJDEP alleges that it has
spent approximately $23 million in interim remedial measures at the PJP
site. The NJDEP also alleges that it will incur approximately $2
million in costs to complete a remedial investigation of the PJP site.
PSE&G has made a good-faith payment of approximately $21,000 to NJDEP
pursuant to the Multi-Site Directive in accordance with actions taken
by certain other PRPs named in these Directives. The NJDEP has filed
a cost recovery action in Superior Court against certain of the other
PRPs named in the Directives. Based upon the claims made and
activities taken to date, PSE&G anticipates that its obligations with
respect to this site will be de minimis.
(6) Claim by EPA, Region III, under CERCLA with respect to a
Superfund Site in Philadelphia, Pennsylvania, owned and formerly
operated by Metal Bank, Inc., as a non-ferrous scrap reclamation
facility. PSE&G, together with several other utilities, is alleged to
be liable either to conduct an RI/FS and undertake the necessary
cleanup, if any, or to reimburse EPA for the cost of performing these
functions. In 1991 these utilities, including PSE&G, entered into an
ACO with the EPA to perform an RI/FS, Docket No. III-91-34-DC. The
RI/FS was completed and the RI/FS Report was submitted to EPA in
October 1994. The RI/FS Report proposes various remedial alternatives
for consideration by EPA in its selection of a remedy for the site.
In July 1995, the EPA issued its Proposed Remedial Action Plan (PRAP)
for the site. The PRAP details the EPA's intention to select a remedy
that will cost between $17 and $30 million. It is anticipated that EPA
will assert a claim against PSE&G and the other utility companies, and
perhaps others as well, for the performance or funding of the selected
remedy. PSE&G's share of the costs of the proposed remedy is between
$4 and $8 million or approximately 26% of the total.
(7) The Klockner Road site is located in Hamilton Township,
Mercer County, New Jersey and occupies approximately two acres on the
Trenton Switching Station property. In May 1995, the NJDEP formally
notified PSE&G that the Klockner Road site is an open case and that
absent voluntary action by PSE&G, the NJDEP would prioritize the site
and thereafter take appropriate enforcement action. As a result of
this notice, PSE&G is in the process of filing an application for a
MOA. Preliminary investigations indicate the potential presence of
soil and groundwater contamination at the site. PSE&G's preliminary
estimate is that an environmental characterization of the site will
cost approximately $800,000. The cost of any remediation of potential
site contamination is not presently estimable.
(8) In U.S. v. CDMG Realty Co., et al., Civil Action No. 89-4246
(NHP) (RJH), pending in the United States District Court for the
District of New Jersey, PSE&G and over 60 other entities were joined
in January 1995 as additional third-party defendants. Third-party
plaintiffs, an association of 44 entities, are essentially seeking
contribution and/or indemnification for the expenses they have incurred
and will incur as a result of having settled the direct claims of the
NJDEP and EPA related to the investigation and remediation of Sharkey's
Landfill, located in Parsippany-Troy Hills, Morris County, New Jersey.
The claims are all alleged to be brought pursuant to CERCLA and PSE&G
is alleged to have arranged for the disposal of industrial wastes at
Sharkey's Landfill. The claims with respect to this matter are
presently the subject of an alternative dispute resolution proceeding.
Based upon the claims made and activities to date, PSE&G estimates that
its obligations for this site will be de minimis.
(9) In 1991, the NJDEP issued Directive and Notice to Insurers
Number Two (Directive Two) to 24 Insurers and 52 Respondents, including
PSE&G in connection with an investigation and remediation of the Global
Landfill Site in Old Bridge Township, Middlesex County New Jersey
(Global Site). Directive Two seeks recovery of past and anticipated
future NJDEP response costs ($37.4 million). PSE&G's alleged liability
is based on assertions that it generated asbestos-containing materials
which were disposed of at the Global Site. In 1991, PSE&G entered into
an agreement with the NJDEP and 29 other Directive Two Respondents
effecting a partial settlement of the foregoing costs subject to a
subsequent reallocation based upon the parties' further development of
information concerning their respective proportionate waste
contributions to the Global Site. Negotiations are ongoing regarding
resolution of the balance of the response costs sought pursuant to
Directive Two. In 1993, the NJDEP and various participating PRPs,
including PSE&G, executed a Consent Decree whereby the participating
PRPs agreed to perform the remedial design and remedial action for the
operable unit one remedy as specified in a 1991 ROD (approximate total
cost $30 million). The Consent Decree was executed and entered by the
United States District Court for the District of New Jersey in 1993.
Subject to a subsequent reallocation, the various parties to the
Consent Decree have agreed that PSE&G's contribution under the Consent
Decree settlement will be $300,000 (approximately 1% of the total
cost).
(10) In 1991, the New Jersey Department of Law and Public Safety,
Division of Law, issued Directive and Notice To Insurers Number One
(Directive One) to 50 Insurers and 20 Respondents, including PSE&G,
seeking from the Respondents payment of $5.5 million of NJDEP's
anticipated costs of remedial action and of administrative oversight
at the Combe Fill South Sanitary Landfill in Washington and Chester
Townships, Morris County, New Jersey (Combe Site). The $5.5 million
represents the NJDEP's 10% share of such anticipated costs pursuant to
a cooperative agreement with the United States regarding the selected
remedial action. Therefore, total site remediation costs approximate
$50 million. Further, the Directive One Respondents are directed to
perform the operation and maintenance of the remedial action including
all remedial facilities on the Combe Site. PSE&G's alleged liability
is based on the assertion that PSE&G-generated waste oil and water,
containing hazardous substances, was transported to the Combe Site and
applied to Combe Site roads for dust control. Based upon the claims
made and PSE&G's investigation and response to same, PSE&G anticipates
that its obligations, if any, with respect to this site will be de
minimis.
(11) In United States of America v. Superior Tube Company, et al.,
Docket No. 89-7421 in the U.S. District Court for the Eastern District
of Pennsylvania, PSE&G was served in 1990 with a Third-Party Complaint.
Pursuant to CERCLA, the United States filed suit against Superior Tube
Company (Superior) and others seeking recovery of past and future costs
incurred or to be incurred in the cleanup of the Moyer Landfill located
in Collegeville, Pennsylvania. Superior filed a Third-Party Complaint
naming approximately 150 third-party defendants, including PSE&G.
Superior alleges that PSE&G generated, transported, arranged for the
disposal of and/or caused to be deposited certain hazardous substances
at the Moyer Landfill. On the basis of those allegations, Superior
seeks contribution and/or indemnification from the third-party
defendants, including PSE&G, on the United States' action against it.
PSE&G has participated in negotiations concerning resolution of the
United States' and Superior Tube's claims. Pursuant to settlement
negotiations amongst certain direct defendants, certain third party
defendants and the plaintiffs, the defending parties participating in
said negotiations are currently pursuing the possibility of resolving
all potential liability concerning the above referenced matter
(excluding any potential liability associated with a future claim, if
any, for natural resource damages) on behalf of certain de minimis
defending parties, including PSE&G. Based upon the claims made and the
above referenced negotiations, PSE&G anticipates that its obligations
with respect to this site will be de minimis.
(12) Spill Act Multi-Site Directive (Directive) issued by the
NJDEP to PRPs, including PSE&G, listing four separate sites, including
the former bulking and transfer facility called the Marvin Jonas
Transfer Station (Sewell Site) in Deptford Township, Gloucester County,
New Jersey. With regard to the Sewell Site, this Directive ordered
approximately 350 PRPs, including PSE&G, to enter into an ACO with
NJDEP, requiring them to remediate the Sewell Site. Certain PRPs,
including PSE&G, have completed the interim actions directed at both
site security and off-site disposal of containers, trailers and
contaminated surface soils. PRPs, including PSE&G, are currently
fulfilling the terms of a MOA entered into with NJDEP in 1993 to
conduct an RI/FS and, if necessary, take remedial action. Based upon
the claims made and activities taken to date, PSE&G anticipates that
its obligations with respect to this site will be de minimis.
(13) In Transtech Industries, Inc. et al v. A&Z Septic Clean et
al., Docket No. 2-90-2578(HAA), filed on October 5, 1992, in the U.S.
District Court for the District of New Jersey, PSE&G has been named a
defendant in a Complaint which has been filed pursuant to CERCLA,
against several hundred parties seeking recovery of past and future
response costs incurred or to be incurred in the investigation and/or
remediation of the Kin-Buc Landfill, located in Edison Township,
Middlesex County, New Jersey. Plaintiffs allege that all named
defendants, including PSE&G, are PRPs as generators and/or transporters
of various hazardous substances ultimately deposited at the Kin-Buc
Landfill. Based upon the claims made and activities taken to date,
PSE&G anticipates that its obligations with respect to this site will
be de minimis.
(14) In 1993, PSE&G acknowledged service of Plaintiff's Summons
and Complaint in a matter entitled The Fishbein Family Partnership v.
PPG Industries, Inc. and Public Service Electric and Gas Company.
Pursuant to CERCLA, the Spill Act and various common law theories of
liability, the Plaintiff filed an action seeking declaratory relief
regarding responsibility for and recovery of damages and response costs
incurred and/or to be incurred as a result of the release or threatened
release of hazardous substances at property located in Jersey City,
Hudson County, New Jersey. Plaintiff named PPG Industries, Inc. (PPG)
and PSE&G as defendants in the above-referenced action. The Plaintiff
alleges that defendants are liable for the damages and relief sought
based on their past conduct of industrial operations at the site. The
industrial operations referenced in Plaintiff's Complaint include
chromium ore processing operations (PPG and its predecessors) and coal
gasification operations (PSE&G and its predecessors). PSE&G filed its
response to the Plaintiff's Complaint including cross-claims for
indemnity and contribution against co-defendant PPG. PSE&G also filed
a Third Party Complaint against UGI Utilities, Inc. (UGI) seeking
indemnification and contribution as to any liability imposed upon PSE&G
attributable to UGI's past conduct of industrial operations on a
portion of the site. In March 1995, PSE&G filed an Amended Third Party
Complaint extending the time period of PSE&G's allegations concerning
UGI's past conduct of industrial operations at the site. In May 1995,
an Administrative Stay of this matter was entered pending either an
agreement between the NJDEP and PPG as to a cleanup plan for the site
or a determination of certain cross-motions for summary judgement filed
by Plaintiff and PPG. Based upon the claims made and activities taken
to date, PSE&G's potential liability in this matter, if any, is not
currently estimable.
Other Potential Liability
In addition to the sites individually listed above, PSE&G has
received 14 claims and/or inquiries concerning prospective enforcement
actions by the EPA and/or NJDEP. Such claims/inquiries relate to
alleged properties/sites where it has been alleged that an imminent and
substantial danger to the public or to the environment exists as a
result of an actual or threatened release of one or more hazardous
substances. PSE&G's investigation and initial response concerning each
such claim and/or inquiry suggests that PSE&G's potential liability,
if any, is de minimis.
Enterprise
----------
Consolidated Financial Statistics (A)
1995 1994 1993 1992 1991
---------- ----------- ----------- ---------- ---------
(Thousands of Dollars where applicable)
Selected Income Information
Operating Revenues
Electric........................... $ 4,020,842 $ 3,739,713 $ 3,696,114 $ 3,407,830 $ 3,519,806
Gas................................ 1,686,403 1,778,528 1,594,341 1,586,181 1,307,849
Nonutility Activities.............. 456,908 404,202 418,135 362,781 283,766
------------ ----------- ----------- ----------- -----------
Total Operating Revenues........... $ 6,164,153 $ 5,922,443 $ 5,708,590 $ 5,356,792 $ 5,111,421
------------ ----------- ----------- ----------- ------------
Net Income......................... $ 662,323 $ 679,033 $ 600,933 $ 504,117 $ 543,035
------------ ----------- ----------- ----------- ------------
Earnings per average share of
Common Stock..................... $ 2.71 $ 2.78 $ 2.50 $ 2.17 $ 2.43
Dividends Paid per Share........... $ 2.16 $ 2.16 $ 2.16 $ 2.16 $ 2.13
Payout Ratio....................... 80% 78% 86% 100% 88%
Rate of Return on Average Common
Equity (B)...................... 12.31% 12.94% 11.91% 10.69% 12.24%
Ratio of Earnings to Fixed Charges. 2.77 2.76 2.59 2.30 2.54
Book Value per Common Share (C).... $ 22.25 $ 21.70 $ 21.07 $ 20.32 $ 20.04
Gross Utility Plant................ $16,925,280 $16,566,058 $15,861,484 $15,081,907 $14,426,560
Accumulated Depreciation and
Amortization of Utility Plant.... $ 5,737,849 $ 5,467,813 $ 5,057,104 $ 4,610,595 $ 4,243,979
Total Assets....................... $17,171,439 $16,717,440 $16,329,656 $14,777,732 $14,804,354
------------- ------------ ----------- ------------ ------------
Consolidated Capitalization
Common Stock....................... $ 3,801,157 $ 3,801,157 $ 3,772,662 $ 3,499,183 $ 3,262,138
Retained Earnings.................. 1,643,785 1,510,010 1,361,018 1,282,931 1,282,029
------------- ------------ ----------- ------------ ------------
Common Equity...................... 5,444,942 5,311,167 5,133,680 4,782,114 4,544,167
Long-Term Debt..................... 5,189,791 5,180,657 5,256,321 4,977,579 5,128,373
Preferred Stock without Mandatory
Redemption....................... 324,994 384,994 429,994 429,994 429,994
Preferred Stock with Mandatory
Redemption....................... 150,000 150,000 150,000 75,000 --
Monthly Income Preferred Securities. 210,000 150,000 -- -- --
------------- ------------ ----------- ------------ ------------
Total Capitalization................$11,319,727 $11,176,818 $10,969,995 $10,264,687 $10,102,534
============= ============ =========== ============ ============
(A) See Management's Discussion and Analysis of Financial Condition and Results of Operations and
Notes to Consolidated Financial Statements.
(B) Net Income for a twelve-month period divided by the thirteen-month average of Common Equity.
(C) Total Common Equity divided by end-of-period Common Shares outstanding.
Operating Statistics
PSE&G
- -----
1995 1994 1993 1992 1991
---------- ----------- ------------ ----------- ------------
(Thousands of Dollars where applicable)
Electric
Revenues from Sales of Electricity:
Residential...................... $ 1,274,712 $ 1,187,099 $ 1,175,875 $ 1,037,099 $ 1,116,699
Commercial....................... 1,853,855 1,734,894 1,678,011 1,554,956 1,575,547
Industrial....................... 704,861 686,065 710,206 683,750 728,411
Public Street Lighting........... 54,730 52,353 51,019 47,729 46,400
----------- ----------- ----------- ----------- -----------
Total Revenues from Sales to
Customers........................ 3,888,158 3,660,411 3,615,111 3,323,534 3,467,057
Interdepartmental.................. 1,862 1,710 1,737 1,544 1,599
Non-Required Energy and
Capacity Revenues.(a)............ 37,179 35,223 48,625 51,313 19,763
Wholesale Energy and Capacity
Revenues.(b)..................... 19,446 7,481 -- -- --
----------- ----------- ----------- ----------- -----------
Total Revenues from Sales of
Electricity...................... 3,946,645 3,704,825 3,665,473 3,376,391 3,488,419
Other Electric Revenues............ 74,197 34,888 30,641 31,439 31,387
----------- ----------- ----------- ----------- -----------
Total Operating Revenues...... $ 4,020,842 $ 3,739,713 $ 3,696,114 $ 3,407,830 $ 3,519,806
=========== =========== =========== =========== ===========
Sales of Electricity - megawatthours:
Residential...................... 10,885,479 10,594,134 10,631,402 9,816,046 10,505,547
Commercial....................... 18,761,863 18,466,863 18,096,312 17,454,352 17,596,569
Industrial....................... 9,026,838 9,109,998 9,203,839 9,298,741 9,406,109
Public Street Lighting........... 339,164 334,726 329,828 325,545 320,900
----------- ----------- ----------- ----------- -----------
Total Sales to Customers........... 39,013,344 38,505,721 38,261,381 36,894,684 37,829,125
Interdepartmental.................. 20,095 17,755 18,514 19,012 19,719
Non-Required Energy Sales.(a)...... 1,047,996 1,320,170 2,245,884 2,116,049 1,858,590
Wholesale Energy Sales.(b)......... 201,610 139,235 -- -- --
----------- ----------- ----------- ----------- -----------
Total Sales of Electricity.... 40,283,045 39,982,881 40,525,779 39,029,745 39,707,434
=========== =========== =========== =========== ===========
Gas
Revenues from Sales of Gas:
Residential...................... $ 823,302 $ 889,541 $ 780,195 $ 809,559 $ 699,696
Commercial....................... 501,102 510,829 460,340 481,960 426,110
Industrial....................... 274,937 312,405 299,762 243,527 138,394
Street Lighting.................. 468 491 467 468 468
----------- ----------- ----------- ----------- -----------
Total Revenues from Sales to
Customers........................ 1,599,809 1,713,266 1,540,764 1,535,514 1,264,668
Interdepartmental.................. 2,636 3,976 3,078 2,572 2,689
----------- ----------- ----------- ----------- -----------
Total Revenues from Sales of Gas... 1,602,445 1,717,242 1,543,842 1,538,086 1,267,357
Transportation Service Revenues.... 54,427 35,057 37,081 34,739 27,036
Other Gas Revenues................. 29,531 26,229 13,418 13,356 13,456
----------- ----------- ----------- ----------- -----------
Total Operating Revenues...... $ 1,686,403 $ 1,778,528 $ 1,594,341 $ 1,586,181 $ 1,307,849
=========== =========== =========== =========== ===========
Sales of Gas - kilotherms:
Residential...................... 1,258,181 1,337,267 1,280,128 1,265,270 1,140,887
Commercial....................... 971,243 945,950 943,054 939,021 893,069
Industrial....................... 942,846 912,689 876,421 739,508 399,385
Street Lighting.................. 670 668 666 668 666
----------- ----------- ----------- ----------- -----------
Total Sales to Customers........... 3,172,940 3,196,574 3,100,269 2,944,467 2,434,007
Interdepartmental.................. 6,139 9,316 7,509 5,967 6,174
----------- ----------- ----------- ----------- -----------
Total Sales of Gas................. 3,179,079 3,205,890 3,107,778 2,950,434 2,440,181
Transportation Service............. 682,693 544,539 557,403 543,097 381,497
----------- ----------- ----------- ----------- -----------
Total Gas Sold and Transported.. 3,861,772 3,750,429 3,665,181 3,493,531 2,821,678
=========== =========== =========== =========== ===========
(a) Non-Required - The sale of excess generation both energy and capacity to other power producers.
(b) Wholesale - Consists of sales for resale to municipalities and to an out of state electric
cooperative under negotiated contracts. Prior to 1994, these sales for resale were treated as
industrial sales.
EDHI
EDHI, a wholly owned, direct subsidiary of Enterprise, is
incorporated under the laws of New Jersey and is the parent company of
EDC, CEA, PSRC, EGDC, Capital and Funding. EDHI's principal executive
offices are located at One Riverfront Plaza, Newark, New Jersey 07102.
EDHI's focus is on investment in the independent energy market. For a
discussion of the impact on EDHI of Enterprise's agreement with the BPU
regarding utility/nonutility activities, see Regulation.
EDC
On December 6, 1995, Enterprise announced that EDHI is pursuing
the divestiture of EDC. Enterprise anticipates that, subject to
satisfying certain conditions, EDHI will divest EDC during 1996, but
no formal plan of divestiture has been approved. The decision stems
from Enterprise's belief that EDC is not fully recognized in the value
of Enterprise's Common Stock and that, with the advent of the energy
futures market, it is not necessary for Enterprise to own large volumes
of oil and gas.
EDC, a New Jersey corporation, has its principal executive offices
at 1000 Louisiana Street, Suite 2900, Houston, Texas 77002. EDC is an
oil and gas exploration and production and marketing company with
principal operations both onshore and offshore in the southern United
States and a growing international production base. EDC will continue
to pursue a program to grow its reserve base through a combination of
strategic acquisitions, high potential exploration activities and
exploitation of its acquired properties and new discoveries. EDC's
worldwide 1995 production totaled 99 BCFE. Year-end 1995 proved
reserves were 630 billion cubic feet of gas and 48 million barrels of
oil, an increase of 6% and a decrease of 1%, respectively, compared to
1994. As of December 31, 1995 and 1994, EDC's consolidated assets
aggregated $756 million and $729 million, respectively. EDC has
operations encompassing about 5.6 million net acres in 13 states,
offshore in the Gulf of Mexico and both onshore and offshore in the
United Kingdom, Argentina, Senegal, Ireland, Tunisia and China. EDC is
exempt from direct regulation by the BPU and FERC except that certain
FERC approval is required to transport its gas interstate from its
discovery fields. (See Note 1 -- Summary of Significant Accounting
Policies of Notes.)
CEA
CEA, a New Jersey corporation, has its principal executive offices
at 1200 East Ridgewood Avenue, Ridgewood, New Jersey 07450. CEA invests
and participates in the development and operation of cogeneration,
thermal and power production facilities, which include domestic QFs,
two foreign EWGs and one foreign utility company. CEA is expected to
be the primary vehicle for EDHI's business growth for the foreseeable
future, with emphasis on international projects. CEA's two direct
subsidiaries, CEA New Jersey, Inc. (CEA New Jersey) and CEA USA, Inc.
(CEA USA), hold certain of its investments. CEA New Jersey's
subsidiaries invest in projects in New Jersey selling power to PSE&G.
CEA USA's subsidiaries invest in projects selling power to other
domestic and foreign entities. CEA and/or its subsidiaries and
affiliates have investments in 22 commercially operating cogeneration
or independent power projects, one anthracite coal mine and one project
under construction. CEA continuously evaluates the status of project
development and construction in light of the realities of timely
completion and the costs incurred.
CEA's investments in QF projects have been undertaken with other
participants because CEA, together with any other utility affiliate,
may not own more than 50% of a QF under applicable law subsequent to
the in-service date. Projects involving EWGs are not restricted to a
50% investment limitation. CEA's projects are diversified
internationally and technologically and are generally financed through
non-recourse debt. CEA is an investor in these projects and the
electricity produced by the facilities is not part of PSE&G's installed
capacity. However, some of such power is being purchased by PSE&G
pursuant to long-term contracts with the applicable projects.
As of December 31, 1995 and 1994, CEA's consolidated assets
aggregated $271 million and $232 million, respectively. (See Note 7 --
Long-Term Investments of Notes.)
PSRC
PSRC, a New Jersey corporation, has its principal executive
offices at One Riverfront Plaza, Newark, New Jersey 07102. PSRC makes
primarily passive investments in assets that can provide funds for
future growth as well as provide incremental earnings for Enterprise.
Investments have been made in leveraged and direct financing leases,
project financings, venture capital funds, leveraged buyout funds, real
estate limited partnerships and securities. The maturities of the
portfolio's investments are also fairly diverse, with some having terms
exceeding 30 years. PSRC's leveraged lease investments include a wide
range of asset sectors. Some of the transactions in which PSRC and its
subsidiaries participate involve other equity investors. PSRC plans to
limit new investments to existing commitments and investments related
to the energy business.
PSRC has a gas marketing subsidiary which markets natural gas and
associated services on an unregulated basis to commercial and
industrial gas consumers nationwide.
PSRC is a limited partner in various partnerships and is committed
to make investments from time to time, upon the request of the
respective general partners. On December 31, 1995, $58 million remained
as PSRC's unfunded commitment subject to call. As of year-end 1995 and
1994, PSRC's long-term investments aggregated $1.4 and $1.3 billion,
respectively.
EGDC
EGDC, a New Jersey corporation having its principal executive
offices at One Riverfront Plaza, Newark, New Jersey 07102, is a
nonresidential real estate development and investment business. EGDC
has investments in ten commercial real estate properties (two of which
are developed) in several states. EGDC's strategy is to preserve and
build the value of its assets to allow for the controlled disposition
of its properties as the real estate market improves. As of December
31, 1995 and 1994, EGDC's consolidated assets aggregated $116 million
and $189 million, respectively.
Capital
Capital, a New Jersey corporation, has its principal executive
offices at 80 Park Plaza, Newark, New Jersey 07101. Capital serves as
a financing vehicle for EDHI's businesses, borrowing on their behalf
on the basis of a minimum net worth maintenance agreement with
Enterprise. That agreement provides, among other things, that
Enterprise (i) maintain its ownership, directly or indirectly, of all
outstanding common stock of Capital, (ii) cause Capital to have at all
times a positive tangible net worth of at least $100,000 and (iii) make
sufficient contributions of liquid assets to Capital in order to permit
it to pay its debt obligations. In 1993, Enterprise agreed with the
BPU to make a good-faith effort to eliminate such Enterprise support
within six to ten years. Intercompany borrowing rates are established
based upon Capital's cost of funds. Effective January 31, 1995, Capital
will not have more than $650 million of debt outstanding at any time.
Capital's assets consist principally of demand notes of EDC, CEA and
PSRC. As of December 31, 1995 and 1994, Capital had outstanding $477.5
million and $632 million, respectively, of its long-term debt. For
additional information, see Construction and Capital Requirements --
Financing Activities and MD&A -- Liquidity and Capital Resources --
EDHI.
Funding
Funding, a New Jersey corporation, has its principal executive
offices at 80 Park Plaza, Newark, New Jersey 07101. Funding serves as
a financing vehicle for EDHI's businesses (excluding EGDC), borrowing
on their behalf, as well as investing their short-term funds.
Short-term investments are made only if the funds cannot be employed
in intercompany loans. Intercompany borrowing rates are established
based upon Funding's cost of funds. Funding is providing both long and
short-term capital for the nonutility businesses other than EGDC on the
basis of an unconditional guaranty from EDHI, but without direct
support from Enterprise. As of December 31, 1995 and 1994, Funding's
assets consisted principally of demand notes of EDC, CEA and PSRC, all
of which are pledged to Funding's lenders and which aggregated $492
million and $334 million, respectively. For additional information, see
MD&A -- Liquidity and Capital Resources -- EDHI.
ITEM 2. PROPERTIES
PSE&G
The statements under this Item as to ownership of properties are
made without regard to leases, tax and assessment liens, judgments,
easements, rights of way, contracts, reservations, exceptions,
conditions, immaterial liens and encumbrances and other outstanding
rights affecting such properties, none of which is considered to be
significant in the operations of PSE&G, except that PSE&G's First and
Refunding Mortgage (Mortgage), securing the bonds issued thereunder,
constitutes a direct first mortgage lien on substantially all of such
property.
PSE&G maintains insurance coverage against loss or damage to its
principal plants and properties, subject to certain exceptions, to the
extent such property is usually insured and insurance is available at
a reasonable cost. For a discussion of nuclear insurance, see Note 12
- -- Commitments and Contingent Liabilities of Notes to Consolidated
Financial Statements.
The electric lines and gas mains of PSE&G are located over or
under public highways, streets, alleys or lands, except where they are
located over or under property owned by PSE&G or occupied by it under
easements or other rights. These easements and rights are deemed by
PSE&G to be adequate for the purposes for which they are being used.
Generally, where payments are minor in amount, no examinations of
underlying titles as to the rights of way for transmission or
distribution lines or mains have been made.
Electric Properties
As of December 31, 1995, PSE&G's share of installed
generating capacity was 10,400 MW, as shown in the following
table:
INSTALLED NET
MEGAWATT PRINCIPAL HEAT GENERATION CAPACITY
NAME AND LOCATION CAPACITY FUEL USED RATE (000 MWH) FACTOR(a)
- -------------------------------------------- --------- --------- ------ --------- ---------
Fossil
Burlington, Burlington, NJ ................. 180 Oil 17,742 30 1.9
Conemaugh, New Florence, PA - 22.50%(b)(c).. 382 Coal 9,380 2,650 79.2
Hudson, Jersey City, NJ .................... 983 Coal 11,351 1,861 21.6
Kearny, Kearny, NJ ......................... 292 Oil 16,221 46 1.8
Keystone, Shelocta, PA - 22.84%(b)(c)....... 388 Coal 9,635 2,643 77.8
Linden, Linden, NJ ......................... 415 Oil 18,007 117 3.2
Mercer, Hamilton, NJ ....................... 642 Coal 10,279 2,087 37.1
Sewaren, Woodbridge Twp., NJ ............... 453 Gas 13,808 360 9.1
------- ------ --------- ---------
Total Fossil........................... 3,735 10,343 9,794 29.9
------- ------ --------- ---------
Nuclear (Capacity factor calculated in
accordance with industries maximum
dependable capability standards)
Hope Creek, Lower Alloways Creek, NJ
95%(b)(c)................................. 979 Nuclear 10,801 6,694 78.9
Peach Bottom, Peach Bottom, PA - 42.49%(b).. 930 Nuclear 10,809 6,976 93.3
Salem, Lower Alloways Creek, NJ
42.59%(b)................................. 942 Nuclear 11,088 1,923 23.4
------- ------ --------- ---------
Total Nuclear(b)(c).................... 2,851 10,843 15,593 62.9
------- ------ --------- ---------
Combined Cycle
Bergen, Ridgefield, NJ..................... 650 Gas 8,034 1,533 26.9
Burlington, Burlington, NJ................. 240 Gas 9,255 513 23.5
------- ------ --------- ---------
Total Combined Cycle.................. 890 8,340 2,046 26.5
------- ------ --------- ---------
Combustion Turbine
Bayonne, Bayonne, NJ........................ 42 Oil 35,297 0.4 0.1
Bergen, Ridgefield, NJ ..................... 21 Oil 111,665 0.8 0.1
Burlington, Burlington, NJ.................. 389 Gas 18,937 7.1 0.2
Edison, Edison Township, NJ ................ 504 Gas 16,532 8.5 0.2
Essex, Newark, NJ .......................... 617 Gas 13,270 279.1 5.2
Hudson, Jersey City, NJ .................... 129 Oil 68,666 0.6 -
Kearny, Kearny, NJ ......................... 504 Oil 18,352 1.7 0.4
Linden, Linden, NJ ......................... 223 Oil 12,635 135.0 3.7
Mercer, Hamilton, NJ ....................... 129 Oil 72,912 0.4 -
National Park, National Park, NJ ........... 21 Oil 0 0.0 -
Salem, Lower Alloways Creek, NJ
42.59%(b)................................. 16 Oil 25,189 0.3 0.1
Sewaren, Woodbridge Township, NJ ........... 129 Oil 45,613 0.8 -
------- ------ --------- ---------
Total Combustion Turbine............... 2,724 13,761 434.7 10.4
------- ------ --------- ---------
Diesel
Conemaugh, New Florence, PA - 22.50%(b)..... 3 Oil 10,101 2.1 0.1
Keystone, Shelocta, PA - 22.84%(b).......... 2 Oil 10,448 5.5 3.1
------- ------ --------- ---------
Total Diesel........................... 5 10,354 7.6 1.7
------- ------ --------- ---------
Pumped Storage
Yards Creek, Blairstown, NJ - 50%(b)(c)..... 195 - 227 13.3
------- ------ --------- ---------
Total PSE&G............................ 10,400(d) 10,531 28,102(e) 30.8
======= ====== ========= =========
(a) Net generation divided by the product of weighted average generating capacity times
total hours.
(b) PSE&G's share of jointly owned facility.
(c) Excludes energy for pumping and synchronous condensers.
(d) Excludes 664 MW of nonutility generation and 200 MW of capacity sales to General
Public Utilities Corporation.
(e) Excludes 5,136 MW of nonutility generation.
/TABLE
For information regarding construction see MD&A -- Construction
and Capital Expenditures.
In addition to the generating facilities in New Jersey and
Pennsylvania as indicated in the table above, as of December 31, 1995,
PSE&G owned 41 switching stations with an aggregate installed capacity
of 31,591,000 kilovolt-amperes, and 222 substations with an aggregate
installed capacity of 7,313,000 kilovolt-amperes. In addition, 6
substations having an aggregate installed capacity of 139,250
kilovolt-amperes were operated on leased property. All of these
facilities are located in New Jersey.
As of December 31, 1995, PSE&G's transmission and distribution
system included 151,449 circuit miles, of which 36,007 miles were
underground, and 789,106 poles, of which 534,106 poles were jointly
owned. Approximately 99% of this property is located in New Jersey.
In addition, as of December 31, 1995, PSE&G owned 4 electric
distribution headquarters and five subheadquarters in four operating
divisions all located in New Jersey.
Gas Properties
As of December 31, 1995, the daily gas capacity of PSE&G's
100%-owned peaking facilities (the maximum daily gas delivery available
during the three peak winter months) consisted of liquid petroleum air
gas (LPG) and liquefied natural gas (LNG) and aggregated 2,973,000
therms (approximately 297,300 Mcf. on an equivalent basis of 1,000
Btu/cubic foot) as shown in the following table:
Daily Capacity
Plant Location (Therms)
- -------------------------------- ------------------ --------------
Burlington LNG.................. Burlington, N.J. 773,000
Camden LPG...................... Camden, N.J. 280,000
Central LPG..................... Edison Twp., N.J. 960,000
Harrison LPG.................... Harrison, N.J. 960,000
---------
Total........................... 2,973,000
=========
As of December 31, 1995, PSE&G owned and operated approximately
15,467 miles of gas mains, owned 12 gas distribution headquarters and
one subheadquarters and leased one other subheadquarters all in two
operating regions located in New Jersey and owned one meter shop in New
Jersey serving all such areas. In addition, PSE&G operated 61 natural
gas metering or regulating stations, all located in New Jersey, of
which 28 were located on land owned by customers or natural gas
pipeline companies supplying PSE&G with natural gas and were operated
under lease, easement or other similar arrangement. In some instances,
portions of the metering and regulating facilities were owned by the
pipeline companies.
Office Buildings and Facilities
PSE&G leases substantially all of a 26-story office tower for its
corporate headquarters at 80 Park Plaza, Newark, New Jersey, together
with an adjoining three-story building. PSE&G also leases other office
space at various locations throughout New Jersey for district offices
and offices for various corporate groups and services. PSE&G also owns
various other sites for training, testing, parking, records storage,
research, repair and maintenance, warehouse facilities and for other
purposes related to its business.
EDHI owns no real property. EDHI leases its corporate headquarters
at One Riverfront Plaza, Newark, New Jersey 07102. For a brief general
description of the properties of the subsidiaries of EDHI, see Item 1.
Business -- EDHI.
ITEM 3. LEGAL PROCEEDINGS
In October 1995, Enterprise received a letter from a
representative of a purported shareholder demanding that it commence
legal action against certain of its officers and directors with regard
to nuclear operations and the current shutdown of the Salem generating
station. In January, 1996, Enterprise and each of its directors except
Forrest J. Remick were served with a civil complaint in a shareholder
derivative action by such purported shareholder on behalf of Enterprise
shareholders (Public Service Enterprise Group Incorporated by G.E.
Stricklin, derivatively vs. E. James Ferland, et al., Docket No.
L1068395, Superior Court of New Jersey, Law Division, Camden County
filed December 27, 1995). The complaint seeks removal of certain
executive officers of PSE&G and Enterprise, certain changes in the
composition of Enterprise's Board of Directors, recovery of damages and
certain other relief for alleged losses purportedly arising out of
PSE&G's operation of the Salem and Hope Creek generating stations. The
Board of Directors has commenced an investigation of the matters raised
in the October demand letter, and that investigation has not yet been
completed. Following conclusion of the investigation, the Board will
meet to determine what action, if any, should be taken with respect to
the complaint filed in the shareholder derivative action.
In addition, see the following, at the pages indicated:
(1) Page 5. Proceedings before FERC relating to competition and
electric wholesale power markets. (Inquiry Concerning the Pricing
Policy for Transmission Services Provided by Utilities Under the
Federal Power Act, Docket No. RM93-19.)
(2) Page 11. Proceedings before the BPU relating to PSE&G's
Second Largest Customer, filed January 6, 1995, in Docket No.
ER95010005.
(3) Page 44. Requests filed in 1974 and later supplemented, to EPA
and NJDEP to establish thermal discharges and intake structures for
PSE&G's electric generating stations (Sewaren Generating Station, NJ
0000680; Hudson Generating Station, NJ 0000647; Kearny Generating
Station, NJ 0000655; Salem Generating Station, NJ 0005622; Linden
Generating Station, NJ 0000663).
(4) Page 46. Notice of Violation issued by EPA against Eagle Point
Cogeneration Partnership regarding alleged violations of air permit.
(5) Pages 48 through 53. Various administrative actions, claims,
litigation and requests for information by federal and/or state
agencies, and/or private parties, under CERCLA, RCRA, and state
environmental laws to compel PRPs, which may include PSE&G, to provide
information with respect to transportation and disposal of hazardous
substances and wastes, and/or to undertake or contribute to the costs
of investigative and/or cleanup actions at various locations because
of actual or threatened releases of one or more potentially hazardous
substances and/or wastes.
(6) Page 74. Proceedings before The BPU relating to New Jersey
Partners in Power Plan filed January 16, 1996, in Docket No.
E096010028.
(7) Page 115. Proceedings before the BPU relating to PSE&G's LGAC,
filed October 2, 1995, in Docket No. GR9510456.
(8) Page 116. Proceedings before the BPU relating to recovery of
replacement power costs in connection with the Salem 1 shutdown, May
5, 1995, Docket No. ER94070293.
(9) Page 116. Proceedings before the BPU relating to PSE&G's LEAC
Remediation Program Costs (RAC), filed July 21, 1995, in Docket No.
GR95070344.
(10) Page 117. Generic proceeding before the BPU relating to
recovery of capacity costs associated with power purchases from
cogenerators, September 16, 1994, in Docket No. EX93060255.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Enterprise and PSE&G, inapplicable.
ITEM 10. EXECUTIVE OFFICERS OF THE REGISTRANTS
Enterprise and PSE&G. Information regarding executive officers
required by this Item is set forth in Part III, Item 10 hereof.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS
Enterprise's Common Stock is listed on the New York Stock
Exchange, Inc. and the Philadelphia Stock Exchange, Inc. All of PSE&G's
common stock is owned by Enterprise, its corporate parent. As of
December 31, 1995, there were 175,831 holders of record of Enterprise
Common Stock.
The following table indicates the high and low sale prices for
Enterprise's Common Stock, as reported in The Wall Street Journal as
Composite Transactions and dividends paid for the periods indicated:
Dividend High Low Per Share
------ ------- ---------
Common Stock:
1995
First Quarter................ 29 7/8 26 .54
Second Quarter............... 30 1/4 26 3/4 .54
Third Quarter................ 29 3/4 26 3/4 .54
Fourth Quarter............... 30 5/8 28 3/4 .54
1994
First Quarter................ 32 27 1/4 .54
Second Quarter............... 29 1/4 25 .54
Third Quarter................ 28 5/8 23 7/8 .54
Fourth Quarter............... 27 1/8 25 .54
Since 1986, PSE&G has made regular cash payments to Enterprise in
the form of dividends on outstanding shares of PSE&G's Common Stock.
PSE&G has paid quarterly dividends on its common stock in each year
commencing in 1948, the year of the distribution of PSE&G's common
stock by Public Service Corporation of New Jersey, the former parent
of PSE&G. Since 1992, EDHI has made regular cash payments to
Enterprise in the form of dividends on outstanding shares of EDHI's
common stock. Enterprise has paid quarterly dividends in each year
commencing with the corporate restructuring of PSE&G when Enterprise
became the owner of all the outstanding common stock of PSE&G. While
the Board of Directors of Enterprise intends to continue the practice
of paying dividends quarterly, amounts and dates of such dividends as
may be declared will necessarily be dependent upon Enterprise's future
earnings, financial requirements and other factors. See MD&A --
Dividends.
The ability of Enterprise to declare and to pay dividends is
contingent upon its receipt of dividend payments from its subsidiaries.
PSE&G has restrictions on the payments of dividends which are contained
in its Restated Certificate of Incorporation, as amended, certain of
the indentures supplemental to its Mortgage and certain debenture bond
indentures. Under these restrictions, dividends on PSE&G's common stock
may be paid only out of PSE&G's earned surplus and may not reduce
PSE&G's earned surplus to less than $10 million. PSE&G dividends on
common stock would be limited to 75% of Earnings Available for Public
Service Enterprise Group Incorporated if payment thereof would reduce
PSE&G's Stock Equity to less than 33 1/3% of PSE&G's Total
Capitalization and would be limited to 50% of Earnings Available for
Public Service Enterprise Group Incorporated if payment thereof would
reduce Stock Equity to less than 25% of PSE&G's Total Capitalization,
as each of said terms is defined in said PSE&G's debenture bond
indentures. Further, under an indenture relating to the loan to PSE&G
of the proceeds of the Monthly Income Preferred Securities of Public
Service Electric and Gas Capital, L.P. (see Note 4. -- Schedule of
Consolidated Capital Stock and Other Securities of Notes), dividends
may not be paid on PSE&G's capital stock as long as any payments on
PSE&G's deferrable interest subordinated debentures issued under said
indenture have been deferred or there is a default under said indenture
or PSE&G's guarantee relating to the Monthly Income Preferred
Securities. None of these restrictions presently limits the payment
of dividends out of current earnings. The amount of Enterprise's and
PSE&G's consolidated retained earnings not subject to these
restrictions at December 31, 1995 was $1.6 billion and $1.4 billion,
respectively.
ITEM 6. SELECTED FINANCIAL DATA
Enterprise
The information presented below should be read in conjunction with Enterprise Consolidated
Financial
Statements and Notes thereto.
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
(THOUSANDS OF DOLLARS, WHERE APPLICABLE)
Total Operating Revenues.... $ 6,164,153 $ 5,922,443 $ 5,708,590 $ 5,356,792 $ 5,111,421
Net Income.................. $ 662,323 $ 679,033 $ 600,933 $ 504,117 $ 543,035
Earnings per average share
of Common Stock........... $ 2.71 $ 2.78 $ 2.50 $ 2.17 $ 2.43
Dividends paid per share of
Common Stock.............. $ 2.16 $ 2.16 $ 2.16 $ 2.16 $ 2.13
As of December 31:
Total Assets.............. $ 17,170,068 $16,717,440 $16,329,656 $14,777,732 $14,804,354
Long-Term Liabilities:
Long-Term Debt....... $ 5,189,791 $ 5,180,657 $ 5,256,321 $ 4,977,579 $ 5,128,373
Other Long-Term
Liabilities........ $ 199,832 $ 215,603 $ 220,159 $ 146,785 $ 162,064
Preferred Stock with
mandatory redemption...... $ 150,000 $ 150,000 $ 150,000 $ 75,000 $ --
Monthly Income Preferred
Securities................ $ 210,000 $ 150,000 $ -- $ -- $ --
Ratio of Earnings to Fixed
Charges plus Preferred
Securities Dividend
Requirements (A).......... 2.77 2.76 2.59 2.30 2.54
(A) Fixed charges include the preferred securities dividend requirements of PSE&G.
PSE&G
The information presented below should be read in conjunction with PSE&G Consolidated Financial
Statements and Notes thereto.
YEARS ENDED DECEMBER 31,
-----------------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
(THOUSANDS OF DOLLARS, WHERE APPLICABLE)
Total Operating Revenues.... $ 5,707,245 $ 5,518,241 $ 5,290,455 $ 4,994,011 $ 4,827,655
Net Income.................. $ 616,964 $ 659,406 $ 614,868 $ 475,936 $ 545,479
As of December 31:
Total Assets.............. $14,555,577 $14,264,398 $13,984,298 $12,273,857 $12,027,970
Long-Term Liabilities:
Long-Term Debt....... $ 4,586,268 $ 4,486,787 $ 4,364,437 $ 3,978,138 $ 3,933,389
Other Long-Term
Liabilities........ $ 199,832 $ 215,603 $ 220,159 $ 146,785 $ 162,064
Preferred Stock with
mandatory redemption...... $ 150,000 $ 150,000 $ 150,000 $ 75,000 $ --
Monthly Income Preferred
Securities................ $ 210,000 $ 150,000 $ -- $ -- $ --
Ratio of Earnings to Fixed
Charges................... 3.25 3.35 3.30 2.70 3.20
Ratio of Earnings to Fixed
Charges plus Preferred
Securities Dividend
Requirements.............. 2.77 2.92 2.89 2.43 2.86
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
ENTERPRISE
Significant factors affecting the consolidated financial condition
and the results of operations of Public Service Enterprise Group
Incorporated (Enterprise) and its subsidiaries are described below.
This discussion refers to the Consolidated Financial Statements and
related Notes of Enterprise and should be read in conjunction with such
statements and notes.
Overview
Enterprise has two direct wholly owned subsidiaries, Public
Service Electric and Gas Company (PSE&G) and Enterprise Diversified
Holdings Incorporated (EDHI). Enterprise's principal subsidiary, PSE&G,
is an operating public utility providing electric and gas service in
certain areas in the State of New Jersey.
EDHI is the parent of Enterprise's nonutility businesses: Energy
Development Corporation (EDC), an oil and gas exploration and
production and marketing company; Community Energy Alternatives
Incorporated (CEA), an investor in and developer and operator of
cogeneration and independent power production (IPP) facilities and
exempt wholesale generators (EWGs); Public Service Resources
Corporation (PSRC), which has made primarily passive investments; and
Enterprise Group Development Corporation (EGDC), a diversified
nonresidential real estate development and investment business. EDHI
also has two finance subsidiaries: PSEG Capital Corporation (Capital),
which provides privately placed debt financing on the basis of a
minimum net worth maintenance agreement from Enterprise and Enterprise
Capital Funding Corporation (Funding), which provides privately placed
debt financing guaranteed by EDHI but without direct support from
Enterprise. Enterprise has been conducting a controlled exit from the
real estate business since 1993 and, in December 1995, announced that
it intends to divest EDC.
As of December 31, 1995 and December 31, 1994, PSE&G comprised 85%
of Enterprise assets. For each of the years 1995, 1994 and 1993, PSE&G
revenues were 93% of Enterprise's revenues and PSE&G's earnings
available to Enterprise for such years were 88%, 91% and 96%,
respectively, of Enterprise's net income.
The major factors which will affect Enterprise's future results
include general and regional economic conditions, PSE&G's customer
retention and growth, the ability of PSE&G and EDHI to meet competitive
pressures and to contain costs, the ability to respond to and take
advantage of opportunities arising from increasing competition in the
utility business, the adequacy and timeliness of rate relief, cost
recovery and necessary regulatory approvals, the ability to continue
to operate and maintain nuclear programs in accordance with Nuclear
Regulatory Commission (NRC) and New Jersey Board of Public Utilities
(BPU) requirements, the impact of environmental regulations, continued
access to the capital markets and continued favorable regulatory
treatment of consolidated tax benefits. (See Note 2 -- Rate Matters,
Note 10 -- Federal Income Taxes and Note 12 -- Commitments and
Contingent Liabilities of Notes to Consolidated Financial Statements
("Notes").)
Competition
The regulatory structure which has historically embraced the
electric and gas industry is in the process of transition. Legislative
and regulatory initiatives, at both the federal and state levels, are
designed to promote competition and will continue to impose additional
pressures on PSE&G's ability to retain customers. In addition, new
technology and interest in self generation and cogeneration have
provided customers with alternative sources of energy.
Over the last several years, the gas industry has been
transformed. Today, commercial and industrial customers can negotiate
their own gas purchases directly with producers or brokers, while PSE&G
is required to provide intrastate transportation of such purchased gas
to the customers' facilities. Although PSE&G is not providing gas
sales service to certain commercial and industrial customers, to date
there has been no negative impact on earnings since sales service and
transportation service tariffs result in the same non-fuel revenue per
therm. Additionally, as a result of this restructuring, PSE&G has been
able to negotiate lower cost gas supplies for those customers who
continue to be part of its bundled rate schedules. A potential
significant competitive challenge could emerge if interstate pipeline
companies are permitted to expand their facilities into PSE&G territory
and provide intrastate transportation to customers. However, this type
of expansion would require federal and state regulatory approvals not
currently in existence.
The restructuring of the electric industry is more complex and
evolving at a slower pace than that of the gas industry. Federal
legislation, such as the National Energy Policy Act (EPAct) has eased
restrictions on independent power producers (IPP) in an effort to
increase competition in the wholesale electric generation market. As
the barriers to entry in the power production business have been
lowered, the construction of cogeneration facilities and independent
power production facilities has been growing, with the result of
creating lower cost alternatives for large commercial and industrial
customers. Presently, PSE&G is in the process of assessing the
potential for individual arrangements with commercial and industrial
customers which have such competitive alternatives, but PSE&G believes
that it does not currently have a material exposure with respect to
such customers.
Further, EPAct authorized the Federal Energy Regulatory Commission
(FERC) to mandate utilities to transport and deliver or "wheel" energy
for the supply of bulk power to wholesale customers. In March 1995,
FERC issued a Notice of Proposed Rulemaking (NOPR) that would require
utilities to (1) establish open access to all wholesale sellers and
buyers, (2) offer transmission service comparable to service they
provide themselves and (3) take transmission service under the same
tariffs offered to other buyers and sellers. FERC's stated position is
that it will ensure that utilities have a fair opportunity to recover
prudently incurred investments that could become stranded costs as a
result of the NOPR.
In the wholesale electric market, other competitive pressures,
such as municipalization, may also have an impact on utilities in the
evolving electric power industry. Municipalization involves the
acquisition and operation of existing investor-owned facilities by a
municipal utility (MUNI) through condemnation, purchase or lease or the
construction and operation of duplicate, parallel facilities within a
municipal boundary. As a result, utilities, such as PSE&G, could lose
customers (residential, commercial and industrial) in the municipality
that is served by the MUNI, as well as lose the municipal entity itself
as a customer.
EPAct granted the states sole authority to mandate retail
wheeling. New Jersey regulators have been reviewing existing
regulations in an effort to develop a revised regulatory structure that
would afford public utilities, such as PSE&G, increased flexibility to
meet the competitive challenges of the future. Phase I of the New
Jersey Energy Master Plan (Phase I), a two-phase plan to better manage
the future energy needs of the State, has been completed. Phase I
called for legislation that would allow New Jersey utilities to
propose, subject to BPU approval, alternatives to rate base/rate of
return pricing, allow for pricing flexibility under certain standards
for customers with competitive options and equalize the impact of tax
policies, such as the New Jersey Gross Receipts and Franchise Tax
(NJGRT) currently assessed on retail energy utility sales, upon all
energy producers. On July 20, 1995, Governor Whitman signed into law
legislation which provides utilities the flexibility
to propose, subject to BPU approval, alternatives to existing rate
base/rate of return pricing and offer negotiated off-tariff agreements
to customers with competitive options. On June 1, 1995, the BPU issued
its order initiating a formal Phase II proceeding of the Master Plan.
The proceeding will address wholesale and retail competition in New
Jersey.
Recoverability of stranded costs is largely dependent on the
transition rules established by regulators, including FERC and the BPU.
Stranded costs that could result as the industry moves to a more
competitive environment include investments in generating facilities,
transmission assets, purchase power agreements where the price being
paid under such an agreement exceeds the market price for electricity
and regulatory assets for which recovery is based solely on continued
cost based regulation. At this time, management cannot predict the
level of stranded costs, if any, or the extent to which regulators will
allow recovery of such costs.
Increased competition and the shift of risks and opportunities
between rate payers and PSE&G resulting from PSE&G's filing of its
proposed Alternative Rate Plan (discussed below) will increase the
emphasis upon electric operational reliability, efficiency and cost.
While the incremental cost of nuclear production is less expensive than
PSE&G's other sources of generation, comparatively high embedded costs
for nuclear plants increase the need for PSE&G to optimize the
utilization of its nuclear generating capacity in order to make its
actual generation output cost competitive.
In order to succeed in this increasingly competitive environment,
Enterprise and its subsidiaries have taken the following steps designed
to retain customers, reduce costs, improve operations and strategically
position itself for future operation:
1) On January 16, 1996, PSE&G filed its proposed alternative rate plan,
the "New Jersey Partners in Power" Plan (Alternative Rate Plan). This
seven-year proposed Alternative Rate Plan allows for a transition to
a competitive energy marketplace while substantially shifting the
business and financial risks and opportunities involved in such
transition away from customers to PSE&G. Some of the key features of
the proposal are: (a) an indexed or price-capped approach to replace
the rate base/rate of return form of regulation including the
discontinuance of the electric Levelized Energy Adjustment Clause
(LEAC) and the BPU's Nuclear Performance Standard (NPS), (b) a
productivity gains sharing mechanism with electric and gas customers,
(c) continued recovery of costs associated with activities mandated by
state or federal agencies and (d) a program of rewards and penalties
based on the performance of certain key overall service indicators,
such as the
duration of customer power outages compared to a five year average.
For a full discussion of the Alternative Rate Plan, see Note 2 -- Rate
Matters of Notes.
2) PSE&G reorganized its senior nuclear leadership team to address
operation and performance issues at PSE&G operated nuclear facilities
and completed a thorough work scope assessment of Salem 1 and Salem 2
in order to return these units to safe, reliable operation over the
long-term.
3) PSE&G reorganized to reflect the evolution toward stand-alone energy
and energy services businesses designed to compete successfully in the
future. The reorganization "unbundled" the services previously
provided by the electric and gas businesses. The focus is now on areas
of business: Generation, Transmission and Distribution and Customer
Services.
4) Also as part of the corporate reorganization, a new business was
created, Enterprise Ventures & Services Corporation, to pursue products
and services which can be marketed beyond traditional geographic and
industry boundaries. Among these are: natural gas marketing in the
wake of deregulation of that industry, conservation and energy
management services and a product development venture with AT&T Corp.
to pilot and eventually market two-way customer communications systems
and services.
5) PSE&G developed initiatives, including the announced closure of five
older, less efficient generating units, to reduce annual fossil
generation operating and maintenance expenses, as well as to reduce
annual fossil capital expenditures.
6) PSE&G has established a deleveraging plan to retire more than $1
billion of outstanding debt over the next five years and to fund its
current five-year construction program entirely through internally
generated cash.
7) PSE&G became the first utility in the Northeast to implement a
service guarantee program. It covers nine key service areas and
provides direct bill credits to customers should PSE&G fail to live up
to its promises.
8) The Strategic Account Marketing Organization was created within
PSE&G to provide more individualized service to its 200 largest
customers.
9) PSE&G received BPU approval for its proposed Experimental Hourly
Energy Pricing Tariff and the first service agreement thereunder with
its second largest customer. This type of agreement serves as an
incentive to retain customers with other energy alternatives in PSE&G's
customer base, as well as in New Jersey.
10) Also in 1995, PSE&G completed the Bergen Repowering Project which
improved the efficiency and environmental effectiveness of the
facility. Fuel costs for the facility will be reduced by approximately
$30 million annually.
11) CEA pursued business opportunities in certain international
markets. During 1995, CEA closed on three projects and a strategic
alliance in China and South America.
12) Enterprise announced that EDHI will pursue the divestiture of EDC.
The decision to divest EDC stems from Enterprise's conclusion that
ownership of large oil and natural gas reserves is no longer necessary
to provide efficient energy solutions to customers and that the true
market value of EDC is not reflected in the price of Enterprise Common
Stock.
Enterprise and its subsidiaries remain committed to the pursuit
of initiatives to contain costs and retain customers.
Accounting for the Effects of Regulation
Currently, PSE&G accounts for the effects of regulation in
accordance with Statement of Financial Accounting Standards No. 71
"Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
In accordance with the provisions of SFAS 71, PSE&G defers certain
expenses (regulatory assets) on the basis that they will be recovered
from customers as part of the ratemaking process. PSE&G believes that
if its proposed Alternative Rate Plan is approved essentially as
proposed, it would continue to meet the criteria to account for certain
utility revenues and expenses in accordance with SFAS 71. However, if
future events or regulatory changes limit PSE&G's ability to establish
prices to recover its costs, PSE&G might conclude that it no longer
meets the application criteria to defer certain expenses in accordance
with SFAS 71. If PSE&G were to discontinue the application of SFAS 71,
the accounting impact would be an extraordinary, non-cash charge to
operations that could be material to the financial position and results
of operations of Enterprise and PSE&G.
PSE&G has certain regulatory assets resulting from the use of a
level of depreciation expense in the rate making process that is less
than the amount that would be recorded under Generally Accepted
Accounting Principles (GAAP) for non-regulated companies. PSE&G cannot
presently quantify what the financial statement impact may be if
depreciation expense were required to be determined absent regulation,
but the impact on the financial position and results of operations of
PSE&G and Enterprise could be material.
Statement of Financial Accounting Standards No. 121 "Accounting
for the Impairment of Long-Lived Assets" (SFAS 121) effective for 1996,
establishes accounting standards for the impairment of long-lived
assets. SFAS 121 also requires that regulatory assets which are no
longer probable of recovery through future revenues be charged to
earnings. The adoption of SFAS 121 is not expected to have a material
impact on the financial position or results of operations of PSE&G and
Enterprise.
PSE&G Energy and Fuel Adjustment Clauses
Under the existing regulatory framework, PSE&G has fuel and energy
tariff rate adjustment clauses, the Levelized Gas Adjustment Charge
(LGAC) and the LEAC, which are designed to permit adjustments for
changes in electric energy and gas supply costs and certain other costs
as approved by the BPU, when compared to cost recovery included in base
rates. Presently, charges under the clauses are primarily based on
energy and gas supply costs which are normally projected over
twelve-month periods except for large gas commercial and industrial
customers for which commencing January 1, 1996, gas supply costs are
projected monthly. The changes in the clauses do not directly affect
earnings because such costs are adjusted monthly to match amounts
recovered through revenues except for the financing costs of carrying
underrecovered balances and required interest payments on net
overrecovered balances. Under the clauses, if actual costs differ from
the costs recovered, the amount of the underrecovery or overrecovery
is deferred. Actual costs otherwise includable in the LEAC are subject
to adjustment by the BPU in accordance with the NPS. (See Note 2 --
Rate Matters and Note 12 -- Commitments and Contingent Liabilities of
Notes.) The Alternative Rate Plan proposes discontinuing LEAC and NPS
and would substantially shift the risks and opportunities involved in
managing changes in fuel and replacement power costs from customers to
PSE&G.
Accounting for Stock Compensation
Statement of Financial Accounting Standards No. 123 "Accounting
for Stock-Based Compensation" (SFAS 123) is effective for fiscal years
that begin after December 15, 1995. SFAS 123 establishes financial
accounting and reporting standards for stock based compensation plans
and includes all arrangements by which employees receive shares of
stock or other equity instruments of the employer or by which the
employer incurs liabilities to employees in amounts based on the price
of the employer's stock. The adoption of SFAS 123 is not expected to
have a material impact on the financial position or results of
operations of PSE&G and Enterprise.
Corporate Policy for the Use of Derivatives
Enterprise and its subsidiaries have established a policy to use
derivatives only for the purpose of managing financial risk and not for
speculative purposes. EDHI currently uses derivatives to manage
financial risk for EDC and PSRC, including its subsidiary United States
Energy Partners (USEP). The derivatives are used to mitigate the
impact on earnings of volatile gas prices for EDC and USEP and volatile
security prices for PSRC's investing activities. For details, see Note
8 -- Financial Instruments and Risk Management of Notes. Although
PSE&G does not currently use derivatives, if the Alternative Rate Plan
is approved as proposed, PSE&G could find derivatives to be a useful
and appropriate tool in managing the volatility of fuel prices, among
other things.
Nuclear Operations
Operation of the Salem units has continued to present challenges
to PSE&G. The units have experienced equipment failures which,
combined with personnel errors, have precipitated or contributed to
plant events or trips which have led to a number of outages over the
lifetime of the units.
Both of the Salem units are currently out of service and their
return dates are subject to completion of testing, analysis, repair
activity and NRC concurrence that they are prepared to restart.
Restart of Salem 1, which had originally been scheduled for the second
quarter of 1996, will be delayed for a substantial period as a result
of the ongoing steam generator inspection and analysis. Salem 2, which
is also undergoing steam generator inspection and analysis is still
scheduled to return to service in the third quarter of 1996. The
inability to successfully return these units to continuous, safe
operation could have a material effect on the financial position,
results of operation and net cash flows of Enterprise and PSE&G.
Results of Operations
Earnings per share of Enterprise Common Stock were $2.71 in 1995,
$2.78 in 1994 and $2.50 in 1993.
In 1995, Enterprise earnings decreased principally due to
increased operating expenses and lower gas sales from PSE&G. These
decreases in earnings were partially offset by improved electric sales,
EDC revenues resulting from the settlement of litigation related to a
take or pay sales contract and from gains realized on sales of
properties by EDC.
In 1994, the increase in Enterprise earnings was driven primarily
by increased weather related electric and gas sales. Enterprise
earnings also benefited from higher investment income from PSRC.
PSE&G - Earnings Available to Enterprise
1995 vs. 1994 1994 vs. 1993
---------------- ---------------
Per Per
Amount Share Amount Share
------ ------ ------ ------
(Millions, except Per Share Data)
PSE&G
Revenues (net of fuel costs and gross
receipts taxes).............................. $ 38 $ .16 $ 147 $ .60
Other operation expenses....................... 10 .04 (77) (.32)
Maintenance expenses........................... (4) (.02) (4) (.02)
Depreciation and amortization expenses......... (39) (.16) (41) (.17)
Federal income taxes........................... (27) (.11) 14 .06
Interest charges............................... (11) (.05) (6) (.02)
Allowance for Funds used During Construction
(AFDC)......................................... (2) (.01) 11 .05
Preferred Securities Dividend Requirements..... (8) (.03) (4) (.02)
Other income and expenses...................... 7 .03 2 .01
----- ----- ----- ----
Earnings Available to Enterprise............... (36) (.15) 42 .17
PSE&G - Revenues
Electric
Revenues increased $281 million, or 7.5%, in 1995 from 1994; 1994
revenues increased $44 million, or 1.2%, compared to 1993. The
significant components of these changes follow:
Increase or (Decrease)
------------------------------
1995 vs. 1994 1994 vs. 1993
------------- -------------
(Millions)
Kilowatthour sales............................... $ 38 $ 69
Recovery of energy costs......................... 189 (26)
NJGRT............................................ 12 (4)
Other operating revenues......................... 42 5
----- -----
Total Electric Revenues.......................... $ 281 $ 44
===== =====
Gas
During 1995, revenues decreased $92 million, or 5.2%, from 1994;
1994 revenues increased $184 million, or 11.6%, over 1993. The
significant components of these changes follow:
Increase or (Decrease)
------------------------------
1995 vs. 1994 1994 vs. 1993
------------- -------------
(Millions)
Therm sales................................... $ (35) $ 61
Recovery of fuel costs........................ (78) 121
NJGRT......................................... 19 (12)
Other operating revenues...................... 2 14
----- -----
Total Gas Revenues................ $ (92) $ 184
===== =====
During 1995, electric revenues were impacted by higher residential
and commercial sales resulting from a recovering economy, warm summer
weather and a modest increase in customer base. In addition, other
electric revenues increased principally due to higher miscellaneous
revenues from increased capacity sales to unaffiliated utilities and
to wholesale customers, service reconnections, temporary services and
revenues from Public Service Conservation Resources Corporation
(PSCRC), PSE&G's energy services subsidiary. Capacity sales are sales
for the reservation of a specified quantity of PSE&G system generating
capacity and must be paid even when the energy is not taken.
In 1995, gas revenues decreased due to the mild winter weather,
partially offset by revenues resulting from the rapidly growing off
system sales and higher gas service contract revenues. Off system
sales are sales of excess gas to brokers and other utilities which are
not part of PSE&G's firm customer base. Earnings on these sales are
shared between the firm customer and PSE&G on an 80/20 split,
respectively.
In 1994, electric and gas revenues benefited from weather related
sales which primarily impacted electric commercial sales and all firm
gas rate schedules. Other electric revenues increased principally due
to increased capacity sales to unaffiliated utilities and increased
miscellaneous revenues, partially offset by lower energy sales to the
unaffiliated utilities. Other gas revenues were significantly impacted
by a one time $10 million legal settlement of a gas contract.
PSE&G - Expenses
Fuel Expenses
As discussed in the PSE&G Energy and Fuel Adjustment Clauses
section, variances in fuel expenses do not directly affect earnings
because of the adjustment clause mechanism. However, if the proposed
Alternative Rate Plan is adopted as filed, future changes in electric
fuel and replacement power costs could impact earnings.
Other Operation Expenses
During 1995, other operation expenses decreased $10 million from
1994 levels. PSE&G had lower nuclear and miscellaneous production
expenses. Nuclear production expenses decreased during 1995 due in
part to the extended outage of Salem Units 1 and 2. PSE&G also secured
savings in miscellaneous expenditures, such as clerical and office
supplies in its steam production area. These savings were partially
offset by increased marketing expenditures for customer related
programs initiated in 1995.
During 1994, other operation expenses increased $77 million when
compared to 1993 principally due to increased nuclear production
expenses which were higher than 1993 levels when Salem had a refueling
outage, increased transmission and distribution expenses incurred
during the bitter 1994 winter and increased administrative and general
expenses primarily due to a rise in personal and property damage claim
expenses. The increase in personal and property damage claims was
directly related to storm damage and other weather related occurrences.
Maintenance Expenses
Maintenance expense increased $4 million in 1995 in comparison to
1994 due to the extended outage at Salem Units 1 and 2, partially
offset by decreased expenses for electric and gas distribution
facilities. Maintenance expense for 1994 was $4 million higher than
in 1993 primarily due to the 1994 Hope Creek refueling outage and
increased expenses for gas distribution facilities which resulted from
the extremely cold weather during January and February 1994.
Depreciation and Amortization Expenses
Depreciation and Amortization expenses increased $39 million in
1995 when compared to 1994 and $41 million in 1994 when compared to
1993. The increases in 1995 and 1994 are attributable to increased
depreciation expenses directly related to increases in plant in
service.
Federal Income Taxes
In 1995, Federal Income Taxes increased $27 million from 1994 and
1994 Federal Income Taxes decreased $14 million from 1993. The 1995
taxes were higher than 1994 principally due to the receipt of a non-
taxable insurance benefit in 1994 and to higher pre-tax operating
income. Federal Income Taxes decreased in 1994 due to the receipt of
a non-taxable insurance benefit, partially offset by higher pre-tax
operating income.
Interest Charges
In 1995, interest charges were $11 million higher than in 1994
and, in 1994, interest charges were $6 million higher than in 1993.
The primary reason for the 1995 increase was higher interest charges
on miscellaneous liabilities, while the driving force behind the 1994
increase was a higher average daily balance of short-term debt
outstanding at higher interest rates.
Allowance for Funds Used During Construction
In 1995, there was a $2 million decrease in AFDC income
principally due to a decrease in construction expenditures. In 1994,
AFDC income was $11 million higher than the 1993 level due to increased
construction resulting from the repowering of the Bergen Generating
Station.
Preferred Securities
Dividend requirements on preferred securities increased $8 million
in 1995 compared to 1994 and $4 million in 1994 compared to 1993. The
increases are the result of the issuance of higher rate Monthly Income
Preferred Securities used to redeem certain issues of PSE&G Preferred
Stock.
EDHI - Net Income
1995 vs. 1994 1994 vs. 1993
---------------- ----------------
Per Per
Amount Share Amount Share
------ ------ ------ ------
(Millions, except Per Share Data)
PSRC..................... -- -- 14 .06
CEA...................... (4) (.02) 2 .01
EDC...................... 23 .10 (34) (.14)
EGDC..................... 1 -- 54 .22
----- ----- ----- -----
Total............ 20 .08 36 .15
===== ===== ===== =====
The net income of EDHI was $80 million in 1995, a $20 million
increase over 1994. EDC's income increased $23 million primarily due
to the realization of a settlement related to a take-or-pay sales
contract. EDC's gains from property sales, higher oil prices and
volumes and reduced depreciation, depletion and amortization (DD&A)
expenses also contributed to higher earnings but were substantially
offset by lower gas prices and volumes. CEA's earnings decreased $4
million compared to 1994 due to higher interest and development
expenses.
The net income of EDHI was $60 million in 1994. Excluding the
impact of an impairment of assets of $51 million, after tax, by EGDC
in 1993, EDHI's earnings in 1994 decreased $15 million in comparison
to 1993. Increased income from PSRC (higher investment income, lower
income taxes compared to 1993 which included the effects of a Federal
income tax increase and lower interest charges) and CEA (higher income
from operating plants) was offset by lower EDC earnings (lower gas
volumes and prices and higher exploration and development expenditures
due to increased drilling activities).
Dividends
The ability of Enterprise to declare and pay dividends is
contingent upon its receipt of dividend payments from its subsidiaries.
PSE&G has made regular payments to Enterprise in the form of dividends
on outstanding shares of its common stock since Enterprise was formed
in 1986. In addition, commencing in 1992, EDHI has also made payments
to Enterprise in the form of dividends on its outstanding common stock.
Since 1992, Enterprise has maintained a constant rate of common stock
dividends. Management believes that gradually reducing the common
stock dividend payout ratio is a prudent policy.
Dividends paid to holders of Enterprise Common Stock increased $.5
million during 1995 compared to 1994 and increased $6 million during
1994 compared to 1993. Such increases were due to the issuance of
additional shares of Enterprise Common Stock.
Dividends paid to holders of PSE&G's Preferred Stock decreased
$6.7 million during 1995 compared to 1994 and increased $2 million
during 1994 compared to 1993. The 1995 decrease in such dividends was
due to the redemption of certain series of Preferred Stock. The
increase in 1994 was due to the issuance of additional shares of
Preferred Stock. (See Liquidity and Capital Resources.)
Dividends paid to holders of Monthly Income Preferred Securities
of Public Service Electric and Gas Capital, L.P. (Partnership), a
limited partnership of which PSE&G is the general partner, increased
$14 million during 1995 compared to 1994. The Partnership's Monthly
Income Preferred Securities were first issued in 1994 and were not
outstanding for the entire year. The increase in 1995 was due to the
issuance of additional securities coupled with the fact that Monthly
Income Preferred Securities were outstanding for the entire year. (See
Note 4 -- Schedule of Consolidated Capital Stock and Other Securities
of Notes.)
Liquidity and Capital Resources
Enterprise's liquidity is affected by maturing debt, investment
and acquisition activities, the capital requirements of PSE&G's and
EDHI's construction and investment programs, permitted regulatory
recovery of expenses and collection of revenues. Capital resources
available to meet such requirements depend upon general and regional
economic conditions, PSE&G's customer retention and growth, the ability
of PSE&G and EDHI to meet competitive pressures and to contain costs,
the adequacy and timeliness of rate relief, cost recovery and necessary
regulatory approvals, the ability to continue to operate and maintain
nuclear programs in accordance with NRC and BPU requirements, the
impact of environmental regulations, continued access to the capital
markets and continued favorable regulatory treatment of consolidated
tax benefits. (For additional information see the discussion of
Competition above and Note 12, Commitments and Contingencies of the
Notes.)
PSE&G
PSE&G had utility plant additions of $686 million, $887 million
and $890 million, for 1995, 1994 and 1993, respectively, including AFDC
of $36 million, $38 million and $27 million, respectively. Construction
expenditures were related to improvements in PSE&G's existing power
plants, transmission and distribution system, gas system and common
facilities. PSE&G also expended $30 million, $34 million and $48
million for the cost of plant removal (net of salvage) in 1995, 1994
and 1993, respectively. Construction expenditures from 1996 through
2000 are expected to aggregate $2.8 billion, including AFDC.
Forecasted construction expenditures are related to improvements in
PSE&G's existing power plants (including nuclear fuel), transmission
and distribution system, gas system and common facilities. (See
Construction, Investments and Other Capital Requirements Forecast
below.)
PSE&G expects that it will be able to internally generate all of
its capital requirements, including construction expenditures, over the
next five years and reduce its debt outstanding by approximately $1
billion, assuming adequate and timely recovery of costs, as to which
no assurances can be given. (See Note 2 -- Rate Matters and Note 12 --
Commitments and Contingent Liabilities of Notes.)
EDHI
During the next five years, a majority of EDHI's capital
requirements are expected to be provided from operational cash flows.
(See Construction, Investments and Other Capital Requirements Forecast
below.) CEA is expected to be the primary vehicle for EDHI's business
growth. A significant portion of CEA's growth is expected to occur in
the international arena due to the current and anticipated growth in
electric capacity required in certain regions of the world. EDC will
continue to pursue a program to grow its reserve base through a
combination of strategic acquisitions, high potential exploration
activities and exploitation of its acquired properties and new
discoveries. EDC's worldwide 1995 production totaled 99 BCFE and, at
year end, EDC had proved reserves of 920 BCFE. EDC expended
approximately $153 million, $188 million and $109 million in 1995, 1994
and 1993, respectively, to acquire, discover or develop domestic and
international reserves. Of these expenditures, $132 million, $160
million and $92 million in 1995, 1994 and 1993, respectively, were
capitalized. These amounts included capitalized interest of $4
million, $4 million and $3 million, respectively. For discussion
regarding the potential divestiture of EDC, see Competition.
PSRC will continue to limit new investments to those related to
the energy businesses, while EGDC will exit the real estate business
in a prudent manner. Over the next several years, EDHI and its
subsidiaries will also be required to refinance a portion of their
maturing debt in order to meet their capital requirements. In addition,
any divestiture of EDC will require the renegotiation of existing loan
agreements of Funding. Any inability to extend or replace maturing
debt and or existing agreements at current levels and interest rates
may affect future earnings and result in an increase in EDHI's cost of
capital.
PSRC is a limited partner in various limited partnerships and is
committed to make investments from time to time, upon the request of
the respective general partners. At December 31, 1995, $58 million
remained as PSRC's unfunded commitment subject to call.
EDHI and each of its subsidiaries are subject to restrictive
business and financial covenants contained in existing debt agreements
and are required to not exceed various debt to equity ratios which vary
from 3:1 to 1.75:1. EDHI is also required to maintain a twelve-months
earnings before interest and taxes to interest (EBIT) coverage ratio
of at least 1.35:1. As of December 31, 1995 and 1994, EDHI had a
consolidated debt to equity ratio of 1.15:1 and, for the years ended
December 31, 1995, 1994 and 1993, EBIT coverage ratios, as defined to
exclude the effects of EGDC, of 2.47:1, 1.94:1 and 2.13:1,
respectively. Compliance with applicable financial covenants will
depend upon future financial position and levels of earnings, as to
which no assurance can be given. (See Note 6 -- Schedule of
Consolidated Debt and Note 16 -- Property Impairment of Enterprise
Group Development Corporation of Notes.)
Long-Term Investments and Real Estate
Long-term investments and real estate increased $82 million in
1995 and decreased $58 million and $67 million in 1994 and 1993,
respectively. The increase in 1995 was primarily due to an increase
in PSCRC's long-term investments of $49 million, PSRC's increase in
investments in partnerships and leases of $52 million and CEA's
increase in partnership investments of $27 million, partially offset
by EGDC's property sales of $53 million. The decrease in 1994 was
primarily due to a $73 million net decrease in PSE&G's investment in
an insurance contract, partially offset by an increase in long-term
investments of $23 million. The decrease in 1993 was due primarily to
EDHI's decrease in long-term investments of $63 million. (For more
details, see Note 7 -- long-term investments and Note 11 -- Leasing
Activities - As Lessor of Notes.)
Construction, Investments and Other Capital Requirements Forecast
1996 1997 1998 1999 2000 TOTAL
------ ------ ------ ------ ----- ------
(MILLIONS OF DOLLARS)
PSE&G (including AFDC)
Electric (including Nuclear).......... 464 408 383 356 342 1,953
Gas................................... 128 117 110 106 102 563
Miscellaneous Corporate............... 70 56 50 41 35 252
------ ------ ------ ------ ------ -----
Total PSE&G Construction Requirements... 662 581 543 503 479 2,768
------ ------ ------ ------ ------ ------
EDHI.................................... 272 148 229 206 225 1,080
------ ------ ------ ----- ------ ------
Mandatory Retirement of Securities:
PSE&G................................. 345 400 118 100 400 1,363
EDHI.................................. 91 125 195 200 78 689
------- ------ ------ ------ ------ ------
436 525 313 300 478 2,052
------- ------ ------ ------ ------ ------
Working Capital and Other - net........ 16 (26) 70 (21) 59 98
------- ------ ------ ------ ------ ------
Total Capital Requirements... $1,386 $1,228 $1,155 $ 988 $1,241 $5,998
======= ====== ====== ====== ====== ======
While the above forecast includes capital costs to comply with revised
Federal Clean Air Act (CAA) requirements through 2000, it does not include
additional requirements being developed under the CAA by Federal and State
agencies. Such additional costs cannot be reasonably estimated at this
time. PSE&G believes that such CAA costs would be recoverable from electric
customers. In accordance with the proposed Alternative Rate Plan, separate
mechanisms would be established to ensure continued recovery of costs
associated with activities mandated or approved by state or federal agencies
or otherwise out of PSE&G's control.
Internal Generation of Cash from Operations
Enterprise's cash from operations is generated primarily from the
operating activities of PSE&G.
Enterprise's cash provided by operations for 1995 increased $261
million to $1.493 billion from 1994. This increase was primarily due
to the increase in PSE&G s revenues (partially offset by an increase
in accounts receivable and unbilled revenues), an increase in the
recovery of electric energy and gas costs through PSE&G's LEAC and LGAC
and a decrease in PSE&G s gross receipts taxes. For additional
information see Results of Operations.
Enterprise's cash provided by operations for 1994 increased $200
million to $1.232 billion from 1993. This increase was primarily due
to the increase in PSE&G's revenues (plus a decrease in accounts
receivable and unbilled revenues) and an increase in the recovery of
electric energy and gas costs through PSE&G's LEAC and LGAC. For
additional information see Results of Operations.
External Financings - PSE&G
In 1995, PSE&G issued $156 million of its First and Refunding
Mortgage Bonds (Bonds)/Medium-Term Notes (MTNs) for the purpose of
redeeming $56 million of its higher cost Bonds and to pay a portion of
its maturing bonds.
In 1995, Partnership issued $60 million of Monthly Income
Preferred Securities, the proceeds of which were used to redeem $60
million of PSE&G's Preferred Stock.
The BPU has authorized PSE&G to issue approximately $4.375 billion
aggregate amount of additional Bonds/MTNs/Preferred Stock/Monthly
Income Preferred Securities through 1997 for refunding purposes. Under
its Mortgage, PSE&G may issue new Bonds against retired Bonds and as
of December 31, 1995, up to $2.840 billion aggregate amount of new
Bonds against previous additions and improvements to utility plant,
provided that the ratio of earnings to fixed charges is at least 2:1.
At December 31, 1995 the ratio was 2.77:1.
In January 1996, PSE&G issued $350 million of Bonds. In February
1996, the net proceeds from the sale were deposited in an escrow
account for the purpose of refunding certain higher cost bonds at their
respective first optional redemption dates in November 1996 and
February 1997.
The BPU has authorized PSE&G to issue and have outstanding at any
one time not more than $1 billion of its short-term obligations,
consisting of commercial paper and other unsecured borrowings from
banks and other lenders through January 1, 1997. On December 31, 1995,
PSE&G had $449 million of short-term debt outstanding.
To provide liquidity for its commercial paper program, PSE&G has
a $500 million one year revolving credit agreement expiring in August
1996 and a $500 million five year revolving credit agreement expiring
in August 2000 with a group of commercial banks, which provides for
borrowing up to one year. On December 31, 1995, there were no
borrowings outstanding under these credit agreements. PSE&G expects
to be able to renew the credit agreement expiring in 1996.
PSCRC has a $30 million revolving credit facility supported by a
PSE&G subscription agreement in an aggregate amount of $30 million
which terminates on March 7, 1996. PSCRC is presently in the process
of negotiating a one year extension for this facility. As of December
31, 1995, PSCRC had $30 million outstanding under this facility.
PSE&G Fuel Corporation (Fuelco) has a $150 million commercial
paper program to finance a 42.49% share of Peach Bottom nuclear fuel,
supported by a $150 million revolving credit facility with a group of
banks, which expires on June 28, 1996. PSE&G has guaranteed repayment
of Fuelco's respective obligations. As of December 31, 1995, Fuelco
had commercial paper of $88 million outstanding under such program.
External Financings - EDHI
Funding has a commercial paper program, supported by a commercial
bank letter of credit and credit facility, in the amount of $225
million expiring in March 1998. As of December 31, 1995, Funding had
$182 million of borrowings outstanding under this commercial paper
program.
Additionally, Funding has a $225 million revolving credit facility
expiring in March 1998. As of December 31, 1995, Funding had $100
million of borrowings outstanding under this facility.
Capital's MTN program has previously provided for an aggregate
principal amount of up to $750 million of MTNs so that its total debt
outstanding at any time, including MTNs, would not exceed such amount.
Effective January 31, 1995, Capital will not have more than $650
million of debt outstanding at any time. In 1995, Capital repaid $112
million of its MTNs. At December 31, 1995, Capital had total debt
outstanding of $478 million, including $355 million of MTNs.
PSE&G
The information required by this item is incorporated herein by
reference to the following portions of Enterprise's Management's
Discussion and Analysis of Financial Condition and Results of
Operations, insofar as they relate to PSE&G and its subsidiaries:
Overview; Competition; PSE&G Energy and Fuel Adjustment Clauses;
Accounting for Stock Compensation; Corporate Policy for the Use of
Derivatives; Nuclear Operations; Results of Operations; Dividends;
Liquidity and Capital Resources; Long-Term Investments and Real Estate;
Construction; Investments and Other Capital Requirements Forecast; and
External Financings.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
FINANCIAL STATEMENT RESPONSIBILITY - ENTERPRISE
Management of Enterprise is responsible for the preparation,
integrity and objectivity of the consolidated financial statements and
related notes of Enterprise. The consolidated financial statements and
related notes are prepared in accordance with generally accepted
accounting principles. The financial statements reflect estimates based
upon the judgment of management where appropriate. Management believes
that the consolidated financial statements and related notes present
fairly Enterprise's financial position and results of operations.
Information in other parts of this Annual Report is also the
responsibility of management and is consistent with these consolidated
financial statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is
engaged to audit Enterprise's consolidated financial statements and
related notes and issue a report thereon. Deloitte & Touche's audit is
conducted in accordance with generally accepted auditing standards.
Management has made available to Deloitte & Touche, all the
corporation's financial records and related data, as well as the
minutes of directors' meetings. Furthermore, management believes that
all representations made to Deloitte & Touche, during its audit were
valid and appropriate.
Management has established and maintains a system of internal
accounting controls to provide reasonable assurance that assets are
safeguarded, and that transactions are executed in accordance with
management's authorization and recorded properly for the prevention and
detection of fraudulent financial reporting, so as to maintain the
integrity and reliability of the financial statements. The system is
designed to permit preparation of consolidated financial statements and
related notes in accordance with generally accepted accounting
principles. The concept of reasonable assurance recognizes that the
costs of a system of internal accounting controls should not exceed the
related benefits. Management believes the effectiveness of this system
is enhanced by an ongoing program of continuous and selective training
of employees. In addition, management has communicated to all employees
its policies on business conduct, safeguarding assets and internal
controls.
The Internal Auditing Department of PSE&G conducts audits and
appraisals of accounting and other operations of Enterprise and its
subsidiaries and evaluates the effectiveness of cost and other controls
and recommends to management, where appropriate, improvements thereto.
Management has considered the internal auditors' and Deloitte &
Touche's recommendations concerning the corporation's system of
internal accounting controls and has taken actions that, in its
opinion, are cost-effective in the circumstances to respond
appropriately to these recommendations. Management believes that, as
of December 31, 1995, the corporation's system of internal accounting
controls is adequate to accomplish the objectives discussed herein.
The Board of Directors of Enterprise carries out its
responsibility of financial overview through its Audit Committee, which
presently consists of six directors who are not employees of Enterprise
or any of its affiliates. The Audit Committee meets periodically with
management as well as with representatives of the internal auditors and
Deloitte & Touche. The Audit Committee reviews the work of each to
ensure that its respective responsibilities are being carried out and
discusses related matters. Both the internal auditors and Deloitte &
Touche periodically meet alone with the Audit Committee and have free
access to the Audit Committee, and its individual members, at any time.
E. James Ferland Robert C. Murray
Chairman of the Board, Vice President and
President and Chief Chief Financial Officer
Executive Officer
Patricia A. Rado
Vice President and Controller
Principal Accounting Officer
February 14, 1996
FINANCIAL STATEMENT RESPONSIBILITY - PSE&G
Management of PSE&G is responsible for the preparation, integrity
and objectivity of the consolidated financial statements and related
notes of PSE&G. The consolidated financial statements and related notes
are prepared in accordance with generally accepted accounting
principles. The financial statements reflect estimates based upon the
judgment of management where appropriate. Management believes that the
consolidated financial statements and related notes present fairly
PSE&G's financial position and results of operations. Information in
other parts of this Annual Report is also the responsibility of
management and is consistent with these consolidated financial
statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is
engaged to audit PSE&G's consolidated financial statements and related
notes and issue a report thereon. Deloitte & Touche's audit is
conducted in accordance with generally accepted auditing standards.
Management has made available to Deloitte & Touche, all the
corporation's financial records and related data, as well as the
minutes of directors' meetings. Furthermore, management believes that
all representations made to Deloitte & Touche, during its audit were
valid and appropriate.
Management has established and maintains a system of internal
accounting controls to provide reasonable assurance that assets are
safeguarded, and that transactions are executed in accordance with
management's authorization and recorded properly for the prevention and
detection of fraudulent financial reporting, so as to maintain the
integrity and reliability of the financial statements. The system is
designed to permit preparation of consolidated financial statements and
related notes in accordance with generally accepted accounting
principles. The concept of reasonable assurance recognizes that the
costs of a system of internal accounting controls should not exceed the
related benefits. Management believes the effectiveness of this system
is enhanced by an ongoing program of continuous and selective training
of employees. In addition, management has communicated to all employees
its policies on business conduct, safeguarding assets and internal
controls.
The Internal Auditing Department conducts audits and appraisals
of accounting and other operations and evaluates the effectiveness of
cost and other controls and recommends to management, where
appropriate, improvements thereto. Management has considered the
internal auditors' and Deloitte & Touche's recommendations concerning
the corporation's system of internal accounting controls and has taken
actions that are cost-effective in the circumstances to respond
appropriately to these recommendations. Management believes that, as
of December 31, 1995, the corporation's system of internal accounting
controls is adequate to accomplish the objectives discussed herein.
The Board of Directors carries out its responsibility of financial
overview through the Audit Committee of Enterprise, which presently
consists of six directors who are not employees of Enterprise or any
of its affiliates. The Enterprise Audit Committee meets periodically
with management as well as with representatives of the internal
auditors and Deloitte & Touche. The Audit Committee reviews the work
of each to ensure that their respective responsibilities are being
carried out and discusses related matters. Both the internal auditors
and Deloitte & Touche, periodically meet alone with the Audit Committee
and have free access to the Audit Committee, and its individual
members, at any time.
E. James Ferland Robert C. Murray
Chairman of the Board Senior Vice President and
and Chief Executive Officer Chief Financial Officer
Patricia A. Rado
Vice President and Controller
Principal Accounting Officer
February 14, 1996
INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors of Public Service Enterprise
Group Incorporated:
We have audited the consolidated balance sheets of Public Service
Enterprise Group Incorporated and its subsidiaries (the "Company") as
of December 31, 1995 and 1994, and the related consolidated statements
of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 1995. Our audits also included
the consolidated financial statement schedules listed in the Index in
Item 14(b)(1). These consolidated financial statements and the
consolidated financial statement schedules are the responsibility of
the Company's management. Our responsibility is to express an opinion
on these consolidated financial statements and consolidated financial
statement schedules 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 Public
Service Enterprise Group Incorporated and its subsidiaries at December
31, 1995 and 1994, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1995
in conformity with generally accepted accounting principles. Also, in
our opinion, such consolidated financial statement schedules, when
considered in relation to the basic consolidated financial statements
taken as a whole, present fairly in all material respects the
information set forth therein.
We have also previously audited, in accordance with generally
accepted auditing standards, the consolidated balance sheets as of
December 31, 1993, 1992, and 1991, and the related consolidated
statements of income, retained earnings and cash flows for the years
ended December 31, 1992 and 1991 (none of which are presented herein)
and we expressed unqualified opinions on those consolidated financial
statements. In our opinion, the information set forth in the Selected
Financial Data for each of the five years in the period ended December
31, 1995 for the Company, presented in Item 6, is fairly stated in all
material respects, in relation to the consolidated financial statements
from which it has been derived.
DELOITTE & TOUCHE LLP
February 14, 1996
Parsippany, New Jersey
INDEPENDENT AUDITORS' REPORT
To the Board of Directors of Public Service Electric and Gas Company:
We have audited the consolidated balance sheets of Public Service
Electric & Gas Company and its subsidiaries (the "Company") as of
December 31, 1995 and 1994, and the related consolidated statements of
income, retained earnings, and cash flows for each of the three years
in the period ended December 31, 1995. Our audits also included the
consolidated financial statement schedules listed in the Index in Item
14(b)(2). These consolidated financial statements and the consolidated
financial statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
consolidated financial statements and consolidated financial statement
schedules 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 Public
Service Electric & Gas Company and its subsidiaries at December 31,
1995 and 1994, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1995 in
conformity with generally accepted accounting principles. Also, in our
opinion, such consolidated financial statement schedules, when
considered in relation to the basic consolidated financial statements
taken as a whole, present fairly in all material respects the
information set forth therein.
We have also previously audited, in accordance with generally
accepted auditing standards, the consolidated balance sheets as of
December 31, 1993, 1992, and 1991, and the related consolidated
statements of income, retained earnings and cash flows for the years
ended December 31, 1992 and 1991 (none of which are presented herein)
and we expressed unqualified opinions on those consolidated financial
statements. In our opinion, the information set forth in the Selected
Financial Data for each of the five years in the period ended December
31, 1995 for the Company, presented in Item 6, is fairly stated in all
material respects, in relation to the consolidated financial statements
from which it has been derived.
DELOITTE & TOUCHE LLP
February 14, 1996
Parsippany, New Jersey
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------
1995 1994 1993
------------ ------------ ------------
(THOUSANDS OF DOLLARS)
OPERATING REVENUES
Electric............................................... $ 4,020,842 $ 3,739,713 $ 3,696,114
Gas.................................................... 1,686,403 1,778,528 1,594,341
Nonutility Activities.................................. 456,908 404,202 418,135
------------ ------------ ------------
Total Operating Revenues........................ 6,164,153 5,922,443 5,708,590
------------ ------------ ------------
OPERATING EXPENSES
Operation
Fuel for Electric Generation and Interchanged
Power............................................. 891,782 695,763 717,136
Gas Purchased and Materials for Gas Produced......... 961,539 1,023,956 897,885
Other................................................ 1,118,758 1,118,523 1,014,455
Maintenance............................................ 312,610 308,080 304,403
Depreciation and Amortization.......................... 674,231 634,028 601,597
Property Impairment (note 16).......................... -- -- 77,637
Taxes
Federal Income Taxes (note 10)....................... 353,997 312,551 313,680
New Jersey Gross Receipts Taxes...................... 612,961 583,167 597,898
Other................................................ 80,565 82,282 77,052
------------ ------------ -----------
Total Operating Expenses........................ 5,006,443 4,758,350 4,601,743
------------ ------------ -----------
OPERATING INCOME......................................... 1,157,710 1,164,093 1,106,847
------------ ------------ -----------
OTHER INCOME
Allowance for Funds Used During
Construction -- Equity............................... 5,324 12,789 12,265
Miscellaneous -- net................................... 8,041 6,430 (3,778)
------------ ------------ -----------
Total Other Income.............................. 13,365 19,219 8,487
------------ ------------ -----------
INCOME BEFORE INTEREST CHARGES AND DIVIDENDS ON
PREFERRED SECURITIES................................... 1,171,075 1,183,312 1,115,334
------------ ------------ -----------
INTEREST CHARGES (note 6)
Long-Term Debt......................................... 434,066 459,158 469,120
Short-Term Debt........................................ 32,822 23,962 13,860
Other.................................................. 29,172 12,805 19,554
------------ ------------ -----------
Total Interest Charges.......................... 496,060 495,925 502,534
Allowance for Funds Used During Construction -- Debt and
Capitalized Interest................................... (37,208) (33,793) (20,833)
------------ ------------ -----------
Net Interest Charges..................................... 458,852 462,132 481,701
------------ ------------ -----------
Preferred Securities Dividend Requirements (note 4)...... 49,426 42,147 38,114
Preferred Stock Redemption Premium....................... 474 -- --
------------ ------------ -----------
Income before cumulative effect of accounting change..... 662,323 679,033 595,519
Cumulative effect of change in accounting for income taxes
(note 10).............................................. -- -- 5,414
------------ ------------ -----------
Net Income............................................... $ 662,323 $ 679,033 $ 600,933
============ ============ ===========
SHARES OF COMMON STOCK OUTSTANDING
End of Year............................................ 244,697,930 244,697,930 243,688,256
Average for Year....................................... 244,697,930 244,470,794 240,663,599
EARNINGS PER AVERAGE SHARE OF COMMON STOCK
Before cumulative effect of accounting change........... $ 2.71 $ 2.78 $ 2.48
Cumulative effect of change in accounting for income
taxes................................................ -- -- .02
------------ ------------ -----------
TOTAL EARNINGS PER AVERAGE SHARE OF COMMON STOCK......... $ 2.71 $ 2.78 $ 2.50
============ ============ ===========
DIVIDENDS PAID PER SHARE OF COMMON STOCK................. $ 2.16 $ 2.16 $ 2.16
============ ============ ===========
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
DECEMBER 31,
---------------------------
1995 1994
----------- -----------
(THOUSANDS OF DOLLARS)
UTILITY PLANT-ORIGINAL COST (note 15)
Electric................................................................ $13,095,103 $12,345,919
Gas..................................................................... 2,442,572 2,318,233
Common.................................................................. 517,104 545,131
----------- -----------
Total............................................................ 16,054,779 15,209,283
Less: accumulated depreciation and amortization........................... 5,440,414 5,147,105
----------- -----------
Net....................................................................... 10,614,365 10,062,178
Nuclear Fuel in Service, net of accumulated amortization --
1995, $297,435; 1994, $302,906........................................ 180,018 205,273
----------- -----------
Net Utility Plant in Service..................................... 10,794,383 10,267,451
Construction Work in Progress, including Nuclear Fuel in Process --
1995, $104,743; 1994, $65,429........................................... 369,082 806,934
Plant Held for Future Use................................................. 23,966 23,860
----------- -----------
Net Utility Plant................................................ 11,187,431 11,098,245
----------- -----------
INVESTMENTS AND OTHER NONCURRENT ASSETS (notes 3,7,8,11,12 and 16)
Long-Term Investments, net of amortization --
1995, $7,213; 1994, $2,365, and net of valuation allowances --
1995, $21,302; 1994, $17,104, respectively............................ 1,822,160 1,625,952
Oil and Gas Property, Plant and Equipment, net of accumulated depreciation
and amortization -- 1995, $786,736; 1994, $748,245.................... 608,015 577,913
Real Estate, Property and Equipment, net of accumulated depreciation --
1995, $5,063; 1994, $14,242, and net of valuation allowances --
1995, $8,228; 1994, $23,264, respectively............................. 75,558 115,210
Other Plant, net of accumulated depreciation and amortization --
1995, $6,531; 1994, $4,653............................................ 27,997 36,063
Nuclear Decommissioning and Other Special Funds......................... 276,348 233,022
Other Assets - net...................................................... 55,974 85,478
----------- -----------
Total Investments and Other Noncurrent Assets.................... 2,866,052 2,673,638
----------- -----------
CURRENT ASSETS
Cash and Cash Equivalents (note 9)...................................... 76,233 67,866
Accounts Receivable:
Customer Accounts Receivable.......................................... 525,404 434,207
Other Accounts Receivable............................................. 260,713 211,779
Less: allowance for doubtful accounts................................ 37,641 40,915
Unbilled Revenues....................................................... 246,876 204,056
Fuel, at average cost................................................... 253,360 268,927
Materials and Supplies, net of inventory valuation reserves --
1995, $20,100; 1994, $18,200, respectively............................ 144,970 148,285
Deferred Income Taxes (note 10)......................................... 27,571 25,311
Miscellaneous Current Assets............................................ 62,631 37,356
----------- -----------
Total Current Assets............................................. 1,560,117 1,356,872
----------- -----------
DEFERRED DEBITS (note 5)
Property Abandonments -- net............................................ 70,120 88,269
Oil and Gas Property Write-Down......................................... 36,078 41,232
Unamortized Debt Expense................................................ 123,833 134,599
Deferred OPEB Costs (notes 1 and 13).................................... 167,189 116,476
Underrecovered Electric Energy and Gas Costs -- net..................... 170,565 172,563
Unrecovered Environmental Costs (notes 2 and 12)........................ 130,070 138,435
Unrecovered Plant and Regulatory Study Costs............................ 35,150 37,128
Unrecovered SFAS 109 Deferred Income Taxes (note 10).................... 769,136 791,393
Deferred Decontamination and Decommissioning Costs (note 3)............. 49,872 53,016
Other................................................................... 5,826 15,574
----------- -----------
Total Deferred Debits............................................ 1,557,839 1,588,685
----------- -----------
Total.......................................................... $17,171,439 $16,717,440
=========== ===========
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
DECEMBER 31,
---------------------------
1995 1994
----------- -----------
(THOUSANDS OF DOLLARS)
CAPITALIZATION (notes 4 and 6)
Common Equity
Common Stock.................................. $ 3,801,157 $ 3,801,157
Retained Earnings............................. 1,643,785 1,510,010
----------- -----------
Total Common Equity...................... 5,444,942 5,311,167
Subsidiaries' Securities and Obligations
Preferred Securities
Preferred Stock Without Mandatory Redemption.. 324,994 384,994
Preferred Stock With Mandatory Redemption..... 150,000 150,000
Monthly Income Preferred Securities........... 210,000 150,000
Long-Term Debt................................... 5,189,791 5,180,657
----------- -----------
Total Capitalization..................... 11,319,727 11,176,818
----------- -----------
OTHER LONG-TERM LIABILITIES
Decontamination, Decommissioning and Low Level
Radwaste Costs (note 3)........................ 50,449 56,149
Environmental Costs (notes 2 and 12).............. 96,272 105,684
Capital Lease Obligations......................... 53,111 53,770
----------- -----------
Total Other Long-Term Liabilities......... 199,832 215,603
----------- -----------
CURRENT LIABILITIES
Long-Term Debt due within one year................ 90,630 499,738
Commercial Paper and Loans (note 6)............... 849,567 491,586
Book Overdrafts................................... 70,014 86,576
Accounts Payable.................................. 567,787 433,471
Other Taxes Accrued............................... 34,678 44,149
Interest Accrued.................................. 108,245 107,962
Estimated Liability for Vacation Pay.............. 17,089 27,080
Customer Deposits................................. 32,785 33,698
Liability for Injuries and Damages................ 38,141 29,814
Miscellaneous Environmental Liabilities........... 16,954 15,365
Other............................................. 95,907 87,480
----------- ----------
Total Current Liabilities................. 1,921,797 1,856,919
----------- ----------
DEFERRED CREDITS
Accumulated Deferred Income Taxes (note 10)....... 3,094,620 2,905,390
Accumulated Deferred Investment Tax Credits ...... 392,324 412,466
Deferred OPEB Costs (notes 1 and 13).............. 167,189 116,476
Other............................................. 75,950 33,768
----------- ----------
Total Deferred Credits.................... 3,730,083 3,468,100
----------- ----------
COMMITMENTS AND CONTINGENT LIABILITIES (note 12)
Total..................................... $17,171,439 $16,717,440
=========== ===========
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------------
1995 1994 1993
---------- ---------- ---------
(THOUSANDS OF DOLLARS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................... $ 662,323 $ 679,033 $ 600,933
Adjustments to reconcile net income to net cash
flows from operating activities:
Depreciation and Amortization................... 674,231 634,028 601,597
Amortization of Nuclear Fuel.................... 75,028 95,173 102,718
Recovery (Deferral) of Electric Energy
and Gas Costs -- net.......................... 1,998 (110,529) (184,770)
Loss from Property Impairments.................. -- -- 77,637
Cumulative Effect of Change in Accounting for
Income Taxes.................................. -- -- (5,414)
Unrealized Gains on Investments -- net.......... (46,668) (26,329) (8,694)
Provision for Deferred Income Taxes -- net...... 145,092 138,919 168,406
Investment Tax Credits -- net................... (20,142) (20,247) (11,655)
Allowance for Funds Used During Construction --
Debt and Equity and Capitalized Interest...... (42,532) (46,582) (33,098)
Proceeds from Leasing Activities -- net......... 37,652 27,682 14,780
Changes in certain current assets and liabilities
Net (increase) decrease in Accounts Receivable
and Unbilled Revenues...................... (186,225) 84,440 (68,382)
Net decrease in Inventory -- Fuel and Materials
and Supplies............................... 18,882 41,169 16,438
Net increase (decrease) in Accounts Payable... 134,316 (85,790) 95,331
Net decrease in Accrued Taxes................. (17,279) (258,818) (293,919)
Net change in Other Current Assets and
Liabilities................................ (12,005) 36,748 (19,505)
Other........................................... 68,244 42,893 (20,732)
---------- ---------- ----------
Net cash provided by operating
activities............................... 1,492,915 1,231,790 1,031,671
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to Utility Plant, excluding AFDC......... (649,883) (849,174) (863,294)
Additions to Oil and Gas Property, Plant and
Equipment, excluding Capitalized Interest....... (127,729) (156,302) (88,864)
Net (increase) decrease in Long-Term Investments
and Real Estate................................. (81,264) 58,416 66,659
Increase in Decommissioning and Other Special
Funds, excluding interest....................... (29,617) (35,394) (45,508)
Cost of Plant Removal -- net....................... (29,674) (33,962) (47,791)
Other.............................................. 29,899 13,933 (14,042)
---------- ---------- ----------
Net cash used in investing activities...... (888,268) (1,002,483) (992,840)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net increase (decrease) in Short-Term Debt......... 357,981 (86,050) 185,654
(Decrease) increase in Book Overdrafts............. (16,562) 23,584 (10,078)
Issuance of Long-Term Debt......................... 156,320 849,800 2,137,700
Redemption of Long-Term Debt....................... (556,294) (593,790) (2,083,453)
Long-Term Debt Issuance and Redemption Costs....... (9,177) (29,811) (72,114)
Issuance of Preferred Stock........................ -- 75,000 75,000
Redemption of Preferred Stock...................... (60,000) (120,000) --
Issuance of Monthly Income Preferred Securities.... 60,000 150,000 --
Issuance of Common Stock........................... -- 28,495 273,479
Cash Dividends Paid on Common Stock................ (528,548) (528,071) (521,572)
Other.............................................. -- (1,970) (6,772)
---------- ---------- ----------
Net cash used in financing activities...... (596,280) (232,813) (22,156)
---------- ---------- ----------
Net increase (decrease) in Cash and Cash
Equivalents........................................ 8,367 (3,506) 16,675
Cash and Cash Equivalents at Beginning of Year....... 67,866 71,372 54,697
---------- ---------- ----------
Cash and Cash Equivalents at End of Year............. $ 76,233 $ 67,866 $ 71,372
========== ========== ==========
Income Taxes Paid.................................... $ 185,376 $ 155,104 $ 140,172
Interest Paid........................................ $ 481,264 $ 432,873 $ 458,956
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------
1995 1994 1993
---------- ---------- ----------
(THOUSANDS OF DOLLARS)
BALANCE JANUARY 1...................................... $1,510,010 $1,361,018 $1,282,931
ADD NET INCOME......................................... 662,323 679,033 600,933
---------- ---------- ----------
Total........................................ 2,172,333 2,040,051 1,883,864
---------- ---------- ----------
DEDUCT
Dividends on Common Stock(A)......................... 528,548 528,071 521,572
Capital Stock Expenses............................... -- 1,970 1,274
---------- ---------- ----------
Total Deductions............................. 528,548 530,041 522,846
---------- ---------- ----------
BALANCE DECEMBER 31.................................... $1,643,785 $1,510,010 $1,361,018
========== ========== ==========
(A) The ability of Enterprise to declare and pay dividends is contingent upon its
receipt of dividend payments from its subsidiaries. PSE&G, Enterprise's
principal subsidiary, has restrictions on the payment of dividends which are
contained in its Restated Certificate of Incorporation, as amended, certain
of the indentures supplemental to its Mortgage and certain other indentures.
However, none of these restrictions presently limits the payment of dividends
out of current earnings. The amount of PSE&G's restricted retained earnings
at December 31, 1995, 1994 and 1993 was $10 million.
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------
1995 1994 1993
---------- ---------- ----------
(THOUSANDS OF DOLLARS)
OPERATING REVENUES
Electric............................................. $4,020,842 $3,739,713 $3,696,114
Gas.................................................. 1,686,403 1,778,528 1,594,341
---------- ---------- ----------
Total Operating Revenues..................... 5,707,245 5,518,241 5,290,455
---------- ---------- ----------
OPERATING EXPENSES
Operation
Fuel for Electric Generation and Interchanged
Power........................................... 891,782 695,763 717,136
Gas Purchased and Materials for Gas Produced...... 961,539 1,036,701 919,870
Other............................................. 949,400 959,859 882,641
Maintenance.......................................... 312,610 308,080 304,403
Depreciation and Amortization........................ 591,114 551,372 510,539
Taxes
Federal Income Taxes (note 10).................... 321,433 294,529 308,790
New Jersey Gross Receipts Taxes................... 612,961 583,167 597,898
Other............................................. 70,904 76,100 67,593
---------- ---------- ----------
Total Operating Expenses..................... 4,711,743 4,505,571 4,308,870
---------- ---------- ----------
OPERATING INCOME....................................... 995,502 1,012,670 981,585
---------- ---------- ----------
OTHER INCOME
Allowance for Funds Used During
Construction -- Equity............................ 5,324 12,789 12,265
Miscellaneous -- net................................. 7,728 6,233 (3,841)
---------- ---------- ----------
Total Other Income........................... 13,052 19,022 8,424
---------- ---------- ----------
INCOME BEFORE INTEREST CHARGES AND DIVIDENDS ON
PREFERRED SECURITIES................................. 1,008,554 1,031,692 990,009
---------- ---------- ----------
INTEREST CHARGES (note 6)
Long-Term Debt....................................... 357,584 366,894 364,252
Short-Term Debt...................................... 20,740 18,175 6,414
Other................................................ 28,545 10,856 19,290
---------- ---------- ----------
Total Interest Charges....................... 406,869 395,925 389,956
Allowance for Funds Used During Construction -- Debt... (30,943) (25,319) (14,815)
---------- ---------- ----------
Net Interest Charges................................... 375,926 370,606 375,141
---------- ---------- ----------
Monthly Income Preferred Securities
Dividend Requirements (note 4)....................... 15,664 1,680 --
---------- ---------- ----------
Net Income............................................. 616,964 659,406 614,868
---------- ---------- ----------
Preferred Stock Dividend Requirements (note 4)......... 33,762 40,467 38,114
Preferred Stock Redemption Premium (note 4)............ 474 -- --
---------- ---------- ----------
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP
INCORPORATED......................................... $ 582,728 $ 618,939 $ 576,754
========== ========== ==========
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
DECEMBER 31,
---------------------------
1995 1994
----------- -----------
(THOUSANDS OF DOLLARS)
UTILITY PLANT-ORIGINAL COST (note 15)
Electric........................................................ $13,095,103 $12,345,919
Gas............................................................. 2,442,572 2,318,233
Common.......................................................... 517,104 545,131
----------- -----------
Total................................................... 16,054,779 15,209,283
Less accumulated depreciation and amortization.................... 5,440,414 5,147,105
----------- -----------
Net............................................................... 10,614,365 10,062,178
Nuclear Fuel in Service, net of accumulated amortization --
1995, $297,435; 1994, $302,906............................... 180,018 205,273
----------- -----------
Net Utility Plant in Service............................ 10,794,383 10,267,451
Construction Work in Progress, including Nuclear Fuel in
Process -- 1995, $104,743; 1994, $65,429........................ 369,082 806,934
Plant Held for Future Use......................................... 23,966 23,860
----------- -----------
Net Utility Plant....................................... 11,187,431 11,098,245
----------- -----------
INVESTMENTS AND OTHER NONCURRENT ASSETS
Long-Term Investments, net of amortization --
1995, $6,009; 1994, $2,365, respectively.................... 119,474 65,886
Nuclear Decommissioning and Other Special Funds (note 3)........ 276,348 233,022
Other Plant, net of accumulated depreciation and amortization --
1995, $1,905; 1994, $1,127.................................. 24,976 32,879
----------- -----------
Total Investments and Other Noncurrent Assets........... 420,798 331,787
----------- -----------
CURRENT ASSETS
Cash and Cash Equivalents (note 9).............................. 32,373 27,498
Accounts Receivable:
Customer Accounts Receivable................................. 525,404 434,207
Other Accounts Receivable.................................... 163,976 151,684
Less: allowance for doubtful accounts........................ 37,641 40,915
Unbilled Revenues............................................... 246,876 204,056
Fuel, at average cost........................................... 253,360 268,927
Materials and Supplies, net of inventory valuation reserves --
1995, $20,100; 1994, $18,200, respectively.................... 143,741 146,763
Deferred Income Taxes (note 10)................................. 27,571 25,311
Miscellaneous Current Assets.................................... 37,130 30,407
----------- -----------
Total Current Assets.................................... 1,392,790 1,247,938
----------- -----------
DEFERRED DEBITS (note 5)
Property Abandonments -- net.................................... 70,120 88,269
Oil and Gas Property Write-Down................................. 36,078 41,232
Unamortized Debt Expense........................................ 122,049 132,342
Deferred OPEB Costs (notes 1 and 13)............................ 167,189 116,476
Underrecovered Electric Energy and Gas Costs -- net............. 170,565 172,563
Unrecovered Environmental Costs (notes 2 and 12)................ 130,070 138,435
Unrecovered Plant and Regulatory Study Costs.................... 35,150 37,128
Deferred Decontamination and Decommissioning Costs (note 3)..... 49,872 53,016
Unrecovered SFAS 109 Deferred Income Taxes (note 10)............ 769,136 791,393
Other........................................................... 5,700 15,574
----------- -----------
Total Deferred Debits................................... 1,555,929 1,586,428
----------- -----------
Total................................................. $14,556,948 $14,264,398
=========== ===========
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
DECEMBER 31,
-------------------------
1995 1994
----------- -----------
(THOUSANDS OF DOLLARS)
CAPITALIZATION (notes 4 and 6)
Common Equity
Common Stock................................... $ 2,563,003 $ 2,563,003
Contributed Capital from Enterprise........... 594,395 534,395
Retained Earnings............................. 1,372,729 1,292,201
----------- -----------
Total Common Equity...................... 4,530,127 4,389,599
Preferred Stock without mandatory redemption....... 324,994 384,994
Preferred Stock with mandatory redemption.......... 150,000 150,000
Monthly Income Preferred Securities of Subsidiary.. 210,000 150,000
Long-Term Debt..................................... 4,586,268 4,486,787
----------- -----------
Total Capitalization..................... 9,801,389 9,561,380
----------- -----------
OTHER LONG-TERM LIABILITIES
Decontamination, Decommissioning and Low Level
Radwaste Costs (note 3)...................... 50,449 56,149
Environmental Costs (notes 2 and 12)............. 96,272 105,684
Capital Lease Obligations (note 11).............. 53,111 53,770
----------- -----------
Total Other Long-Term Liabilities......... 199,832 215,603
----------- -----------
CURRENT LIABILITIES
Long-Term Debt due within one year................ -- 310,200
Commercial Paper and Loans (note 6)............... 567,316 401,759
Book Overdrafts................................... 70,014 86,576
Accounts Payable.................................. 481,632 370,005
Accounts Payable - Associated Companies (note 19). 8,011 16,677
Other Taxes Accrued............................... 32,767 36,030
Interest Accrued.................................. 95,811 95,721
Estimated Liability for Vacation Pay.............. 17,089 27,080
Customer Deposits................................. 32,785 33,698
Liability for Injuries and Damages................ 38,141 29,814
Miscellaneous Environmental Liabilities........... 16,954 15,365
Other............................................. 50,751 50,778
----------- -----------
Total Current Liabilities................. 1,411,271 1,473,703
----------- -----------
DEFERRED CREDITS
Accumulated Deferred Income Taxes (note 10)....... 2,535,603 2,478,539
Accumulated Deferred Investment Tax Credits ...... 370,610 389,721
Deferred OPEB Costs (notes 1 and 13).............. 167,189 116,476
Other............................................. 71,054 28,976
----------- -----------
Total Deferred Credits.................... 3,144,456 3,013,712
----------- -----------
COMMITMENTS AND CONTINGENT LIABILITIES (note 12)
Total..................................... $14,556,948 $14,264,398
=========== ===========
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31,
---------------------------------------
1995 1994 1993
----------- ----------- -----------
(THOUSANDS OF DOLLARS)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income................................................. $ 616,964 $ 659,406 $ 614,868
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization........................... 591,114 551,372 510,539
Amortization of Nuclear Fuel............................ 75,028 95,173 102,718
Recovery (Deferral) of Electric Energy and Gas
Costs -- net........................................ 1,998 (110,529) (184,770)
Provision for Deferred Income Taxes -- net.............. 79,321 108,163 175,868
Investment Tax Credits -- net........................... (19,111) (19,208) (18,408)
Allowance for Funds Used During Construction -- Debt and
Equity................................................ (36,267) (38,108) (27,080)
Changes in certain current assets and liabilities
Net (increase) decrease in Accounts Receivable
and Unbilled Revenues.............................. (149,583) 74,891 (78,953)
Net decrease in Inventory -- Fuel and Materials
and Supplies....................................... 18,589 41,163 16,920
Net increase (decrease) in Accounts Payable........... 102,961 (99,788) 83,421
Net decrease in Accrued Taxes......................... (11,071) (261,037) (286,119)
Net change in Other Current Assets and Liabilities.... (2,100) 36,245 (27,790)
Other................................................... 57,158 22,763 (49,006)
----------- ----------- -----------
Net cash provided by operating activities............. 1,325,001 1,060,506 832,208
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to Utility Plant, excluding AFDC................. (649,883) (849,174) (863,294)
Net (increase) decrease in Long-Term Investments........... (65,189) 50,668 (26,980)
Net increase in Decommissioning Funds and Other Special
Funds, excluding interest............................... (29,617) (35,394) (45,508)
Cost of Plant Removal -- net............................... (29,674) (33,962) (47,791)
Other...................................................... 859 1,692 (13,607)
----------- ----------- -----------
Net cash used in investing activities................. (773,504) (866,170) (997,180)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Net increase (decrease) in Short-Term Debt................. 165,557 (130,969) 275,192
(Decrease) increase in Book Overdrafts..................... (16,562) 23,584 (10,078)
Issuance of Long-Term Debt................................. 156,320 849,800 1,972,700
Redemption of Long-Term Debt............................... (367,039) (478,950) (1,716,401)
Long-Term Debt Issuance and Redemption Costs............... (8,462) (29,731) (68,227)
Issuance of Preferred Stock................................ -- 75,000 75,000
Redemption of Preferred Stock.............................. (60,000) (120,000) --
Issuance of Monthly Income Preferred Securities............ 60,000 150,000 --
Contributed Capital by Enterprise.......................... 60,000 -- 174,670
Cash Dividends Paid........................................ (535,962) (545,767) (531,314)
Other...................................................... (474) (1,970) (754)
----------- ----------- -----------
Net cash (used in) provided by financing activities... (546,622) (209,003) 170,788
----------- ----------- -----------
Net increase (decrease) in Cash and Cash Equivalents......... 4,875 (14,667) 5,816
Cash and Cash Equivalents at Beginning of Year............... 27,498 42,165 36,349
----------- ----------- -----------
Cash and Cash Equivalents at End of Year..................... $ 32,373 $ 27,498 $ 42,165
=========== =========== ===========
Income Taxes Paid............................................ $ 279,873 $ 209,196 $ 172,869
Interest Paid................................................ $ 399,509 $ 345,867 $ 356,620
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------------
1995 1994 1993
---------- ---------- ----------
(THOUSANDS OF DOLLARS)
BALANCE JANUARY 1...................................... $1,292,201 $1,180,532 $1,097,734
ADD NET INCOME......................................... 616,964 659,406 614,868
---------- ---------- ----------
Total........................................ 1,909,165 1,839,938 1,712,602
---------- ---------- ----------
DEDUCT CASH DIVIDENDS(A)
Preferred Stock, at required rates................... 33,762 40,467 38,114
Common Stock......................................... 502,200 505,300 493,200
ADJUSTMENT TO RETAINED EARNINGS........................ 474 1,970 756
---------- ---------- ----------
Total Deductions............................. 536,436 547,737 532,070
---------- ---------- ----------
BALANCE DECEMBER 31.................................... $1,372,729 $1,292,201 $1,180,532
========== ========== ==========
(A) The Company has restrictions on the payment of dividends which are contained
in its Restated Certificate of Incorporation, as amended, and certain of the
indentures supplemental to its Mortgage and certain other indentures.
However, none of these restrictions presently limits the payment of dividends
out of current earnings. The amount of the Company's restricted retained
earnings at December 31, 1995, 1994 and 1993 was $10 million.
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Public Service Enterprise Group (Enterprise) has two direct wholly
owned subsidiaries, Public Service Electric and Gas Company (PSE&G) and
Enterprise Diversified Holdings Incorporated (EDHI). Enterprise's
principal subsidiary, PSE&G, is an operating public utility providing
electric and gas service to customers in certain areas in the State of
New Jersey. As of December 31, 1995, PSE&G comprised 85% of
Enterprise's assets and for the year ending on that date, 93% of its
revenues. Of the 150,000,000 authorized shares of PSE&G common stock
at December 31, 1995, there were 132,450,344 shares outstanding, with
an aggregate book value of $2.6 billion.
PSE&G has a finance subsidiary, PSE&G Fuel Corporation (Fuelco),
providing financing, unconditionally guaranteed by PSE&G, of up to $150
million aggregate principal amount at any one time of a 42.49% interest
in the nuclear fuel acquired for Peach Bottom Atomic Power Station
Units 2 and 3 (Peach Bottom). PSE&G also has a subsidiary, Public
Service Conservation Resources Corporation (PSCRC) which offers demand
side management (DSM) services to utility customers. In 1994, Public
Service Electric and Gas Capital, L.P. (Partnership), a limited
partnership in which PSE&G is the general partner, was formed for the
purpose of issuing Monthly Income Preferred Securities. (See Note 4 --
Schedule of Consolidated Capital Stock and Other Securities.) In 1995,
PSE&G created a new subsidiary, Enterprise Ventures and Services, to
pursue products and services beyond traditional geographic and industry
boundaries.
EDHI is the parent of Enterprise's nonutility businesses: Energy
Development Corporation (EDC), an oil and gas exploration and
production and marketing company; Community Energy Alternatives
Incorporated (CEA), an investor in and developer and operator of
cogeneration and independent power production facilities; Public
Service Resources Corporation (PSRC), which makes primarily passive
investments; and Enterprise Group Development Corporation (EGDC), a
nonresidential real estate development and investment business. EDHI
also has two finance subsidiaries: PSEG Capital Corporation (Capital)
and Enterprise Capital Funding Corporation (Funding).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Consolidation Policy
The consolidated financial statements include the accounts of
Enterprise and its subsidiaries. All significant intercompany accounts
and transactions have been eliminated in consolidation. Certain
reclassifications of prior years' data have been made to conform with
the current presentation.
Regulation -- PSE&G
The accounting and rates of PSE&G are subject, in certain respects,
to the requirements of the New Jersey Board of Public Utilities (BPU)
and the Federal Energy Regulatory Commission (FERC). As a result, PSE&G
maintains its accounts in accordance with their prescribed Uniform
Systems of Accounts, which are the same. The applications of Generally
Accepted Accounting Principles (GAAP) by PSE&G differ in certain
respects from applications by non-regulated businesses. PSE&G prepares
its financial statements in accordance with the provisions of Statement
of Financial Accounting Standards No. 71 -- "Accounting for the Effects
of Certain Types of Regulation" (SFAS 71). In general, SFAS 71
recognizes that accounting for rate-regulated enterprises should
reflect the relationship of costs and revenues. As a result, a
regulated utility may defer recognition of cost (a regulatory asset)
or recognize an obligation (a regulatory liability) if it is probable
that, through the rate-making process, there will be a corresponding
increase or decrease in revenues. Accordingly, PSE&G has deferred
certain costs, which will be amortized over various periods. To the
extent that collection of such costs or payment of liabilities is no
longer probable as a result of changes in regulation and/or PSE&G's
competitive position, the associated regulatory asset or liability will
be reversed with a charge or credit to income. (See Note 5 -- Deferred
Items.) If PSE&G were to discontinue the application of SFAS 71, the
accounting impact would be an extraordinary, non-cash charge to
operations that could be material to the financial position and results
of operations of Enterprise and PSE&G.
Amounts charged to operations for depreciation expense reflect
estimated useful lives and methods, which include estimates of cost of
removal and salvage, prescribed and approved by regulators rather than
those that might otherwise apply to non-regulated enterprises. PSE&G
cannot presently quantify what the financial statement impact may be
if depreciation expense were to be determined absent regulation.
Utility Plant and Related Depreciation -- PSE&G
Additions to utility plant and replacements of units of property
are capitalized at original cost. The cost of maintenance, repairs and
replacements of minor items of property is charged to appropriate
expense accounts. At the time units of depreciable property are
retired or otherwise disposed of, the original cost less net salvage
value is charged to accumulated depreciation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Depreciation is computed under the straight-line method.
Depreciation is based on estimated average remaining lives of the
several classes of depreciable property. These estimates are reviewed
on a periodic basis and necessary adjustments are made as approved by
the BPU. Depreciation provisions stated in percentages of original
cost of depreciable property were 3.52% in 1995, 3.51% in 1994 and
3.46% in 1993.
Use of Estimates
The process of preparing financial statements in conformity with
GAAP requires the use of estimates and assumptions regarding certain
types of assets, liabilities, revenues and expenses. Such estimates
primarily relate to unsettled transactions and events as of the date
of the financial statements. Accordingly, upon settlement, actual
results may differ from estimated amounts.
Decontamination and Decommissioning -- PSE&G
In 1993, FERC issued Order No. 557 on the accounting and rate-
making treatment of special assessments levied under the National
Energy Policy Act of 1992 (EPAct). Order No. 557 provides that special
assessments are a necessary and reasonable current cost of fuel and
shall be fully recoverable in rates in the same manner as other fuel
costs. In accordance with its filed Alternative Rate Plan, PSE&G has
requested to have separate mechanisms to ensure continued recovery of
costs associated with activities mandated or approved by state or
federal agencies, but no assurances can be given that the BPU will
authorize such recovery from customers. (See Note 2 -- Rate Matters
and Note 3 -- PSE&G Nuclear Decommissioning and Amortization of Nuclear
Fuel - Uranium, Decontamination and Decommissioning Fund.)
Amortization of Nuclear Fuel -- PSE&G
Nuclear energy burnup costs are charged to fuel expense on a
units-of-production basis over the estimated life of the fuel. Rates
for the recovery of fuel used at all nuclear units include a provision
of one mill per kilowatthour (KWH) of nuclear generation for spent fuel
disposal costs. (See Note 3 -- PSE&G Nuclear Decommissioning and
Amortization of Nuclear Fuel.)
Revenues and Fuel Costs -- PSE&G
Revenues are recorded based on services rendered to customers
during each accounting period. PSE&G records unbilled revenues
representing the estimated amount customers will be billed for services
rendered from the time meters were last read to the end of the
respective accounting period. Rates include projected fuel costs for
electric generation, purchased and interchanged power, gas purchased
and materials used for gas production. Any under or overrecoveries,
together with interest (in the case of net overrecoveries), are
deferred and included in operations in the period in which they are
reflected in rates.
Long-Term Investments
PSRC has invested in securities and limited partnerships investing
in securities, which are recorded at fair value, and various leases and
other limited partnerships. EGDC is a participant in the nonresidential
real estate markets. CEA is an investor in and developer and operator
of cogeneration and power production facilities. (See Note 7 --
Long-Term Investments.)
Derivatives
Gains and losses on hedges of existing assets or liabilities are
included in the carrying amounts of those assets and liabilities and
are ultimately recognized in income as part of those carrying amounts.
Gains and losses related to qualifying hedges of firm commitments or
anticipated transactions also are deferred and recognized in income or
as adjustments of carrying amounts when the hedged transaction occurs.
(See Note 8 -- Financial Instruments and Risk Management.)
Oil and Gas Accounting -- EDC
EDC uses the successful efforts method of accounting under which
proved leasehold costs are capitalized and amortized over the proved
developed and undeveloped reserves on a unit-of-production basis.
Drilling and equipping costs, except exploratory dry holes, are
capitalized and depreciated over the proved developed reserves on a
unit-of-production basis. Estimated future abandonment costs of
offshore proved properties are depreciated on a unit-of-production
basis over the proved developed reserves. Estimated future abandonment
costs of onshore properties are estimated to be offset by the salvage
value of the tangible equipment. Unproved leasehold costs are
capitalized and not amortized, pending an evaluation of the exploration
results. Unproved leasehold and producing properties costs are assessed
periodically to determine if an impairment of the cost of significant
individual properties has occurred. The cost of an impairment is
charged to expense. Costs incurred for exploratory dry holes,
exploratory geological and geophysical work and delay rentals are
charged to expense as incurred.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Income Taxes
Enterprise and its subsidiaries file a consolidated Federal income
tax return and income taxes are allocated to Enterprise's subsidiaries
based on taxable income or loss of each. Investment tax credits are
deferred and amortized over the useful lives of the related property,
including nuclear fuel.
Effective January 1, 1993, Enterprise and its subsidiaries adopted
Statement of Financial Accounting Standards No. 109 "Accounting for
Income Taxes" (SFAS 109). Under SFAS 109, deferred income taxes are
provided for all temporary differences between the financial statement
carrying amounts and the tax bases of existing assets and liabilities
irrespective of the treatment for rate-making purposes. For periods
prior to January 1, 1993, PSE&G provided deferred income taxes to the
extent permitted for rate-making purposes. (See Note 10 -- Federal
Income Taxes.)
Allowance for Funds Used During Construction (AFDC) and Capitalized
Interest
PSE&G -- AFDC represents the cost of debt and equity funds used to
finance the construction of new utility facilities. The amount of AFDC
capitalized is reported in the Consolidated Statements of Income as a
reduction of interest charges for the borrowed funds component and as
other income for the equity funds component. The rates used for
calculating AFDC in 1995, 1994 and 1993 were 6.98%, 6.48% and 6.96%,
respectively. These rates were within the limits set by FERC.
EDHI -- The operating subsidiaries of EDHI capitalize interest
costs allocable to construction expenditures at the average cost of
borrowed funds.
Pension Plan and Other Postretirement Benefits
The employees of PSE&G, other than non represented employees
commencing service after January 1, 1996, as well as those of
participating affiliates, are covered by a noncontributory trusteed
pension plan (Pension Plan) from the date of hire. New represented
employees of PSE&G who commence service after January 1, 1996 are
covered by a Cash Balance Pension Plan. The policy is to fund pension
costs accrued. PSE&G also provides certain health care and life
insurance benefits to active and retired employees. The portion of such
costs pertaining to retirees amounted to $33 million, $29 million, and
$28 million in 1995, 1994 and 1993, respectively. The current cost of
these benefits is charged to expense when paid and is currently being
recovered from ratepayers.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On January 1, 1993, Enterprise and PSE&G adopted Statement of
Financial Accounting Standards No. 106, "Employers Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106), which requires
that the expected cost of employees' postretirement health care
benefits be charged to expense during the years in which employees
render service. Prior to 1993, Enterprise and PSE&G recognized
postretirement health care costs in the year in which the benefits were
paid. PSE&G elected to amortize over 20 years its unfunded obligation
at January 1, 1993. (See Note 13 -- Postretirement Benefits Other Than
Pensions and Note 14 -- Pension Plan.)
NOTE 2. RATE MATTERS
Alternative Rate Plan
On January 16, 1996, PSE&G proposed to the BPU major changes in
utility regulation that include an immediate $50 million rate reduction
for its electric customers, various types of rate freezes, assurances
that future price increases related to controllable costs will be lower
than the rate of inflation and funding of up to an aggregate of $55
million in two economic development initiatives.
The seven-year "New Jersey Partners in Power" Plan (Plan), if
approved, would give PSE&G the mechanisms and incentives to compete
more effectively on several fronts, including the ability to develop
revenue from non-regulated products and services, accelerate or modify
depreciation schedules to help mitigate any potential stranded asset
issue and more aggressively manage the control of costs. In addition,
the Plan would provide the foundation for ongoing price flexibility
without the need for prolonged, adversarial regulatory proceedings.
The Plan begins the process for a transition to a more competitive
energy marketplace while substantially shifting the business and
financial risks and opportunities involved in this transition away from
customers to PSE&G and enhancing PSE&G's ability to make the necessary
human, intellectual and financial investments required to stimulate
innovation and productivity.
Key energy pricing features of the proposed Plan are as follows:
Upon the BPU's approval of the Plan, PSE&G will reduce electric
rates across the board by $50 million annually as an upfront
guaranteed share of the productivity improvements that it expects
to achieve over the life of the Plan.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
New rates for all PSE&G electric customers reflecting the
reduction would be established through a merger of existing base
tariffs and the electric Levelized Energy Adjustment Clause (LEAC)
and would be frozen at these levels through December 31, 1996. In
addition, the Plan proposes the elimination of the BPU's existing
Nuclear Performance Standard (NPS). This discontinuance of the
LEAC and NPS would result in substantially shifting the risks and
opportunities involved in managing changes in fuel and replacement
power costs from customers to PSE&G. Gas fuel costs will continue
to be recovered on a dollar for dollar basis from customers under
the existing Levelized Gas Adjustment Charge (LGAC).
In order to create incentives to lower costs and improve
efficiency and productivity, the Plan would rely on a
comprehensive external price cap index based upon changes in the
Gross Domestic Product Price Index (GDPPI) and a separate fuel
price index mechanism, reduced by a fixed productivity offset of
0.30% to establish optional annual price changes each January 1st
for electricity. In addition, the Plan would rely on an index for
non-fuel gas prices calculated on the basis of changes in the
GDPPI, reduced by a fixed productivity offset of 0.35%, to
establish optional annual price changes each January 1st. The
price cap mechanisms would become effective on January 1, 1997 and
would assure that any rate increase related to controllable costs
would be below the rate of inflation, guaranteeing that these
costs would decline in real terms.
Under the Plan, PSE&G would establish an initial service block
equal to the first 150 kilowatthours (KWH) of usage for
residential electric customers who would be protected from price
cap index increases through December 31, 2002, the proposed
expiration date of the Plan. Similarly, an initial service block
equal to 40 therms would be set for residential gas customers and
protected from index increases over the same period of time. In
addition, public street lighting prices would not be subject to
index increases for the life of the Plan.
The Plan includes a productivity gains sharing mechanism. This
mechanism has been designed to provide incentives to maximize
efficiency and productivity improvements and ensure that electric and
gas customers receive an increasing share of productivity gains using
returns on equity as a proxy for these gains. The gains, which would
be awarded through bill credits, would be based on a threshold earnings
level defined as PSE&G's established return on equity of 12% plus a 100
basis points neutral zone above that level. Customers would receive a
10% share of the gains from the first 50 basis points above the
threshold level. Their share would increase by an additional 10% for
each subsequent increase of 50 basis points up to a maximum of 50%.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Separate mechanisms also would be established to ensure continued
recovery of costs associated with activities mandated or approved
by state or federal agencies or otherwise out of PSE&G's control.
These costs include demand side management programs, environmental
remediation, costs associated with non-utility electric
generators, nuclear decommissioning funding and nuclear fuel
assessment costs. These mechanisms would assure that PSE&G
recovers only actual costs related to these activities.
The Plan would allow for electric and non-fuel gas prices to be
changed to reflect exogenous events beyond the control of PSE&G
and would be subject to modification for industry restructuring.
The Plan calls for an increase of $50 million in annual
depreciation expenses for PSE&G's Hope Creek nuclear generating
station -- $25 million effective January 1, 1997, and an
additional $25 million effective January 1, 1998. In addition,
the Plan proposes a transfer of depreciation reserves totaling
$253 million from transmission and distribution to fossil steam
electric generating accounts. The Plan would permit depreciation
to be changed annually following BPU review and approval.
In addition to the pricing features, the Plan guarantees enhanced
quality of customer services through PSE&G's recently established
service guarantee program for electric and gas customers and specific
incentive and penalty mechanisms based on various service indicators.
The Plan would establish a program of rewards and penalties in key
overall service indicators such as duration of customer power outages
compared to a historic five-year average.
In addition to these service quality incentives, the Plan would
establish rewards and penalties based on the movement of PSE&G's
average electric residential rate measured against the national average
of residential electric rates. Rewards or penalties of up to $5 million
would be implemented if comparisons indicate that PSE&G's residential
rates decreased or increased by more than one-half of one percent
relative to the national average.
A major component of the Plan is a proposed economic and market
development and retention assurance program. This would allow flexible
pricing and promote special economic development activities designed
to enhance the economic vitality of the State of New Jersey. One aspect
of the program would give PSE&G the ability to quickly establish new
optional electric or gas rates or individual customer contracts to
serve new markets and retain or attract individual customers.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Also under the Plan, PSE&G would fund two economic development
initiatives. The first is a private sector leadership investment of $5
million in the New Jersey Fund for Community Economic Development. The
second new initiative is the establishment of the PSE&G Economic
Development Fund in which PSE&G would commit to investing up to $50
million for financing significant economic development projects within
PSE&G's service territory over the seven years of the Plan.
In addition, the Plan calls for establishment of a State Emissions
Trading Bank (Bank) for economic development and environmental
improvement. PSE&G would donate 1,000 tons of nitrogen oxide emissions
credits to the Bank for use in economic development. This is intended
as a key step to linking economic development with sound environmental
policy and building on New Jersey's leadership role in seeking a
regional solution to air pollution problems.
Under the Plan, price levels associated with the recovery of Gross
Receipts and Franchise Tax (GRFT) or successor taxes will be directly
adjusted in such a manner as to insure their full and timely recovery
from ratepayers.
PSE&G cannot predict what action, if any, may be taken by the BPU
with respect to the Plan.
Levelized Gas Adjustment Charge
On October 2, 1995, PSE&G petitioned the BPU for modifications to
its LGAC, requesting that:
(a) The LGAC be renamed to the Levelized Gas Incentive Clause
(LGIC);
(b) A benchmark be established for certain gas delivered from the
Gulf Coast, and any difference between PSE&G's actual gas
purchase costs and the benchmark price, either positive or
negative, be shared 50/50 between customers and PSE&G;
(c) The current annual LGAC rate be converted to a monthly rate
for firm commercial and industrial customers; and
(d) A fixed annual margin would be credited to LGAC for certain
interruptible rate schedules, while actual margins from such
sales will be retained by PSE&G. Any differences, positive
or negative, will be absorbed by PSE&G.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
On December 20, 1995, the BPU approved an interim Stipulation to
include the implementation of monthly pricing on the commodity portion
of the LGAC rate for firm commercial and industrial customers effective
January 1, 1996. The incentive proposal relating to interruptible
sales (request (d)) above was withdrawn. The remaining aspects of
PSE&G's October 2, 1995 petition remain the subject of continued
investigation and litigation.
Electric Levelized Energy Adjustment Clause
By Order dated May 5, 1995, the BPU approved PSE&G's LEAC. Such
Order also required that a hearing be convened regarding the April 1994
Salem 1 shutdown, to determine whether PSE&G should be allowed to
recover replacement power costs of approximately $8 million which have
been deferred. On October 18, 1995, this matter was ordered to be
transmitted to the Office of Administrative Law (OAL) for hearing.
PSE&G cannot predict the outcome of this proceeding.
Remediation Adjustment Charge
On July 21, 1995, PSE&G petitioned the BPU to recover Remediation
Program costs incurred during the period August 1, 1994 through July
31, 1995. In accordance with a BPU Order dated November 4, 1994, the
petition proposes to recover, effective October 1, 1995, $2.5 million
from gas customers and $1.6 million from electric customers.
Consolidated Tax Benefits
In a case affecting another utility in which neither Enterprise nor
PSE&G were parties, the BPU considered the extent to which tax savings
generated by nonutility affiliates included in the consolidated tax
return of that utility's holding company should be considered in
setting that utility's rates. In September, 1992, the BPU approved an
order in such case treating certain consolidated tax savings generated
after June 30, 1990 by that utility's nonutility affiliates as a
reduction of its rate base. In December, 1992, the BPU issued an order
approving a stipulation in PSE&G's 1992 base rate proceeding which
resolved the case without separate quantification of the consolidated
tax issue. The stipulation did not provide final resolution of the
consolidated tax issue for any subsequent base rate filing. While
Enterprise continues to account for its two wholly-owned subsidiaries
on a stand-alone basis, resulting in a realization of the tax benefits
by the entity generating the benefit, an ultimate unfavorable
resolution of the consolidated tax issue could reduce PSE&G's and
Enterprise's future revenue and net income. In addition, an unfavorable
resolution
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
may adversely impact Enterprise's nonutility investment strategy.
Enterprise believes that PSE&G's taxes should be treated on a
stand-alone basis for rate-making purposes, based on the separate
nature of the utility and nonutility businesses. However, neither
Enterprise nor PSE&G is able to predict what action, if any, the BPU
may take concerning consolidation of tax benefits in future rate
proceedings. (See Note 10 -- Federal Income Taxes.)
Other Rate Matters
On July 21, 1995, the BPU initiated a generic proceeding to
expeditiously adopt specific standards to guide utility "off-tariff"
negotiated rate agreement programs, which proceeding would consider
minimum prices, confidentiality, maximum contract duration, filing
requirements and such other standards as necessary for compliance with
the law. A Written Summary Decision and Order was issued on October
27, 1995, which ordered each New Jersey electric utility, including
PSE&G, to file initial minimum tariffs, consistent with the terms of
such Order, and further, indicated that such Order will be supplemented
by a Final Decision and Order to fully discuss and explain the
rationale for the BPU's overall decision. On November 13, 1995 PSE&G
filed its compliance filing. PSE&G cannot predict what impact, if any,
the generic tariff may have on its electric revenues and earnings.
In September 1994, the BPU initiated a generic proceeding regarding
recovery of capacity costs associated with electric utility power
purchases from cogeneration and small power procedures. The initial
phase of the proceeding, which has been transmitted to the Office of
Administrative Law, seeks to determine whether there was any such
overrecovery and, if so, the amount overrecovered.
The New Jersey Division of Ratepayer Advocate has intervened in the
proceeding and alleges, among other things, that PSE&G has
overrecovered such costs ranging from $250 to $300 million during the
period from August 1991 to December 1994. PSE&G denies such
overrecovery because its capacity cost recovery mechanisms were
approved by the BPU as to each of its cogeneration contracts and as to
its base rates. Additionally, PSE&G contends that a review of any
individual cost item is inappropriate and that the BPU has previously
found that, during the period under review, PSE&G did not overearn
compared to its established return. Moreover, PSE&G contends that the
Ratepayer Advocate's assertion is proscribed as retroactive ratemaking.
While PSE&G cannot predict the outcome of this proceeding, the
final resolution of this issue may impact the financial position,
results from operations or net cash flows of Enterprise and PSE&G on
a prospective basis.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3. PSE&G NUCLEAR DECOMMISSIONING AND AMORTIZATION OF NUCLEAR FUEL
The BPU decision in PSE&G's 1992 base rate case utilized studies
based on the prompt removal/dismantlement method of decommissioning for
all of PSE&G's nuclear generating stations. This method consists of
removing all fuel, source material and all other radioactive materials
with activity levels above accepted release limits from the nuclear
sites. PSE&G has an ownership interest in five nuclear units: Salem 1
and Salem 2 -- 42.59% each, Hope Creek -- 95% and Peach Bottom 2 and
3 -- 42.49% each. In accordance with rate orders received from the BPU,
PSE&G has established an external master nuclear decommissioning trust
for all of its nuclear units. The Internal Revenue Service (IRS) has
ruled that payments to the trust are tax deductible. PSE&G's total
estimated cost of decommissioning its share of these 5 nuclear units
is estimated at $681 million in year-end 1990 dollars (the year that
the site specific estimate was prepared), excluding contingencies. The
1992 base rate decision provided that $15.6 million of such costs are
to be collected through base rates and an additional annual amount of
$7.0 million in 1993 and $14 million each year thereafter are to be
recovered through PSE&G's LEAC. In accordance with the filed
Alternative Rate Plan, PSE&G has requested to have separate mechanisms
to ensure continued recovery of costs associated with activities
mandated or approved by state or federal agencies, but no assurances
can be given that the BPU will authorize such recovery from customers
(see Note 2 -- Rate Matters). At December 31, 1995 and 1994, the
accumulated provision for depreciation and amortization included
reserves for nuclear decommissioning for PSE&G's units of $292 million
and $249 million, respectively. As of December 31, 1995 and 1994, PSE&G
had contributed $220 million and $190 million, respectively, into
independent external qualified and nonqualified nuclear decommissioning
trust funds.
On January 3, 1996, PSE&G filed with the BPU its 1995 nuclear plant
decommissioning cost update. The filing includes decommissioning cost
updates for PSE&G's respective ownership share of Salem, Hope Creek and
Peach Bottom. PSE&G's filing was based on the existing Nuclear
Regulatory Commission (NRC) generic formula(s). PSE&G does not believe
that the NRC generic estimates provide an accurate estimate of the cost
of decommissioning because the NRC formula does not factor into its
cost estimates the cost of removal of nonradiological structures and
equipment and interim spent fuel storage installations. PSE&G is
currently completing site specific studies in order to update its
filing with the BPU during 1996.
The Staff of the Securities and Exchange Commission (SEC) has
questioned certain of the current accounting practices of the electric
utility industry, including PSE&G, regarding the recognition,
measurement and classification of decommissioning costs for nuclear
generating stations in the financial statements of electric utilities.
In response to these questions, the Financial Accounting Standards
Board (FASB) has agreed to review the accounting for removal costs,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
including decommissioning. If current electric utility industry
accounting practices for such decommissioning are changed: (1) annual
provisions for decommissioning could increase, (2) the estimated cost
for decommissioning could be recorded as a liability rather than as
accumulated depreciation and (3) trust fund income from the external
decommissioning trusts could be reported as investment income rather
than as a reduction to decommissioning expense.
Uranium Enrichment Decontamination and Decommissioning Fund
In accordance with EPAct, domestic utilities that own nuclear
generating stations are required to pay a cumulative total of $150
million each year (adjusted for inflation) into a decontamination and
decommissioning fund, based on their past purchases of enrichment
services from the United States Department of Energy (DOE) Uranium
Enrichment Enterprise (now a federal government corporation known as
the United States Enrichment Corporation (USEC)). These amounts are
being collected over a period of 15 years or until $2.25 billion
(adjusted for inflation) has been collected. Under this legislation,
PSE&G's obligation for the nuclear generating stations in which it has
an interest is $67 million (adjusted for inflation). Since 1993, PSE&G
has paid $17 million, resulting in a balance due of $50 million. PSE&G
has deferred the expenditures incurred to date as part of deferred
underrecovered electric energy costs and expects to recover its costs
in the next LEAC. In accordance with the filed Alternative Rate Plan,
PSE&G has requested to have separate mechanisms to ensure continued
recovery of costs associated with activities mandated or approved by
state or federal agencies, but no assurances can be given that the BPU
will authorize such recovery from customers (see Note 2 -- Rate
Matters).
Spent Nuclear Fuel Disposal Costs
In accordance with the Nuclear Waste Policy Act (NWPA), PSE&G has
entered into contracts with the DOE for the disposal of spent nuclear
fuel. Payments made to the DOE for disposal costs are based on nuclear
generation and are included in Fuel for Electric Generation and
Interchanged Power in the Statements of Income. These costs are
recovered through the LEAC. In accordance with the filed Alternative
Rate Plan, PSE&G has requested to have separate mechanisms to ensure
continued recovery of costs associated with activities mandated or
approved by state or federal agencies, but no assurances can be given
that the BPU will authorize such recovery from customers (see Note 2 --
Rate Matters).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4. SCHEDULE OF CONSOLIDATED CAPITAL STOCK AND OTHER SECURITIES
CURRENT
REDEMPTION
OUTSTANDING PRICE DECEMBER 31, DECEMBER 31,
SHARES PER SHARE 1995 1994
----------- ---------- ------------ ------------
(THOUSANDS OF DOLLARS)
ENTERPRISE COMMON STOCK (no par) - note (A) --
authorized 500,000,000 shares; issued and
outstanding at December 31, 1995, and
December 31, 1994, 244,697,930 shares,
and at December 31, 1993, 243,688,256 shares. $3,801,157 $3,801,157
ENTERPRISE PREFERRED SECURITIES (note B)
PSE&G CUMULATIVE PREFERRED SECURITIES (note C)
Without Mandatory Redemption (notes D and E)
$100 par value series
4.08%................................ 250,000 103.00 $ 25,000 $ 25,000
4.18%................................ 249,942 103.00 24,994 24,994
4.30%................................ 250,000 102.75 25,000 25,000
5.05%................................ 250,000 103.00 25,000 25,000
5.28%................................ 250,000 103.00 25,000 25,000
6.80%................................ 250,000 102.00 25,000 25,000
6.92%................................ 600,000 -- 60,000 60,000
7.40%................................ 500,000 101.00 50,000 50,000
7.52%................................ 500,000 101.00 50,000 50,000
7.70% (note E)....................... -- -- -- 60,000
$25 par value series
6.75%................................ 600,000 -- $ 15,000 $ 15,000
---------- ----------
Total Preferred Stock without
Mandatory Redemption............... $ 324,994 $ 384,994
========== ==========
With Mandatory Redemption (notes D and F)
$100 par value series
7.44%................................ 750,000 -- $ 75,000 $ 75,000
5.97%................................ 750,000 -- 75,000 75,000
---------- ----------
Total Preferred Stock With
Mandatory Redemption (note G)...... $ 150,000 $ 150,000
========== ==========
Monthly Income Preferred Securities (notes D, F, G and H)
9.375%............................... 6,000,000 -- $ 150,000 $ 150,000
8.00%................................ 2,400,000 -- $ 60,000
---------- ----------
Total Monthly Income Preferred Securities $ 210,000 $ 150,000
========== ==========
(A) Total authorized and unissued shares include 7,302,488 shares of Enterprise Common Stock reserved
for issuance through Enterprise's Dividend Reinvestment and Stock Purchase Plan and various employee
benefit plans. In 1995, no shares of Enterprise Common Stock were issued or sold and in 1994,
1,009,674 shares were issued and sold for $28,495,122.
(B) Enterprise has authorized a class of 50,000,000 shares of Preferred Stock without par value, none
of which is outstanding.
(C) As of December 31, 1995, there were 2,900,058 shares of $100 par value and 9,400,000 shares of $25
par value Cumulative Preferred Stock which were authorized and unissued, and which upon issuance
may or may not provide for mandatory sinking fund redemption. If dividends upon any shares of
Preferred Stock are in arrears in an amount equal to the annual dividend thereon, voting rights for
the election of a majority of PSE&G's Board of Directors become operative and continue until all
accumulated and unpaid dividends thereon have been paid, whereupon all such voting rights cease,
subject to being again revived from time to time.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(D) At December 31, 1995, the annual dividend requirement and embedded dividend for Preferred Stock
without mandatory redemption were $20,046,765 and 6.14%, respectively, and for Preferred Stock with
mandatory redemption were $10,057,500 and 6.75%, respectively.
At December 31, 1994, the annual dividend requirement and embedded dividend for Preferred Stock
without mandatory redemption were $24,666,763 and 6.39%, respectively and for Preferred Stock with
mandatory redemption were $10,057,500 and 6.75%, respectively.
At December 31, 1995, the annualized monthly income requirement of the Monthly Income Preferred
Securities and their embedded cost were $18,862,500 and 6.04%, respectively.
At December 31, 1994, the annualized monthly income requirement of the Monthly Income Preferred
Securities and their embedded cost were $14,062,500 and 6.31%, respectively.
(E) On October 16, 1995, PSE&G redeemed all of the 600,000 shares of its outstanding 7.70% Cumulative
Preferred Stock ($100 par), at a redemption price of $100.79.
(F) For information concerning fair value of financial instruments, see Note 8 -- Financial Instruments
and Risk Management.
(G) On September 12, 1995, Partnership issued 2,400,000 shares of its 8% Monthly Income Preferred
Securities, Series A, with a stated liquidation preference of $25 each.
(H) Public Service Electric and Gas Capital, L.P. (Partnership) was formed for the purpose of issuing
Monthly Income Preferred Securities. The proceeds of Monthly Income Preferred Securities sales are
lent to PSE&G and evidenced by PSE&G's Deferrable Interest Subordinated Debentures. If and for as
long as payments on PSE&G's Deferred Interest Subordinated Debentures have been deferred, or PSE&G
has defaulted on the indenture related thereto or its guarantee thereof, PSE&G may not pay any
dividends on its Capital Stock.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 5. DEFERRED ITEMS
Property Abandonments
The BPU has authorized PSE&G to recover after-tax property abandonment costs from its customers. The
following table reflects the application of Statement of Financial Accounting Standards No. 90, "Regulated
Enterprises -- Accounting for Abandonments and Disallowances of Plant Costs," as amended (SFAS 90), on
property abandonments, and related tax effects, for which no return is earned. The net-of-tax discount rate
used was between 4.443% and 7.801%. (See Note 2 -- Rate Matters.) The following table reflects property
abandonments:
DECEMBER 31, 1995 DECEMBER 31, 1994
------------------ ------------------
DISCOUNTED DISCOUNTED
PROPERTY ABANDONMENTS COST TAXES COST TAXES
- ------------------------------------------------ ---------- ------- ---------- -------
(THOUSANDS OF DOLLARS)
Atlantic Project................................ $ 58,221 $ 24,440 $ 70,130 $29,453
LNG Project..................................... 2,992 957 7,287 2,635
Uranium Projects................................ 8,907 3,871 10,852 4,677
-------- ------- -------- -------
$ 70,120 $ 29,268 $ 88,269 $36,765
======== ======= ======== =======
Under (Over) Recovered Electric Energy and Gas Costs -- net
Recoveries of electric energy and gas costs are determined by the BPU under the LEAC and LGAC.
PSE&G's deferred fuel balances as of December 31, 1995 and December 31, 1994, reflect underrecovered
costs as follows:
DECEMBER 31,
-------------------
1995 1994
------ ------
(Millions)
Underrecovered Electric Energy Costs......... $162.4 $172.0
Underrecovered Gas Fuel Costs................ 8.2 .6
------ ------
Total................................... $170.6 $172.6
====== ======
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Unrecovered Plant and Regulatory Study Costs
Amounts shown in the consolidated balance sheets consist of costs
associated with developing, consolidating and documenting the specific
design basis of PSE&G's jointly owned nuclear generating stations, as
well as PSE&G's share of costs associated with the cancellation of the
Hydrogen Water Chemistry System Project (HWCS Project) at Peach Bottom.
PSE&G has received both BPU and FERC approval to defer and amortize,
over the remaining life of the Salem and Hope Creek nuclear units,
costs associated with configuration baseline documentation and the
canceled HWCS Project. PSE&G has received FERC approval to defer and
amortize over the remaining life of the applicable Peach Bottom units,
costs associated with the configuration baseline documentation and the
canceled HWCS Project. In accordance with the filed Alternative Rate
Plan, PSE&G has requested to have separate mechanisms to ensure
continued recovery of costs associated with activities mandated or
approved by state or federal agencies or otherwise out of PSE&G's
control (see Note 2 -- Rate Matters).
Unamortized Debt Expense
Gains and losses and the costs of issuing and redeeming long-term
debt for PSE&G are deferred and amortized over the life of the
applicable debt.
Oil and Gas Property Write-Down
On December 31, 1992, the BPU approved the recovery of PSE&G's
deferral of an EDC write-down through PSE&G's LGAC over a ten-year
period beginning January 1, 1993. At December 31, 1995 and 1994, the
remaining balance to be amortized was $36.1 million and $41.2,
respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 6. SCHEDULE OF CONSOLIDATED DEBT
LONG-TERM
DECEMBER 31,
--------------------------
INTEREST RATES DUE 1995 1994
- ----------------- --------- ---------- ----------
(THOUSANDS OF DOLLARS)
PSE&G
FIRST AND REFUNDING MORTGAGE BONDS (note A)
4 3/4% - 6% 1995........... $ -- $ 310,000
6 7/8% - 7 1/8% 1997........... 300,000 300,000
6% 1998........... 100,000 100,000
8 3/4% 1999........... 100,000 100,000
6% - 7 5/8% 2000........... 400,000 400,000
6 1/8% - 9 1/8% 2001-2005........... 1,125,000 1,125,000
6.30% - 6.90% 2006-2010........... 177,990 234,310
6.80% - 7 3/8% 2011-2015........... 198,500 198,500
Variable 2011-2015........... 42,620 --
6.45% - 8.10% 2016-2020........... 29,600 29,600
Variable 2016-2020........... 13,700 --
5.20% - 9 1/4% 2021-2025........... 1,263,500 1,267,500
5.70% - 6.55% 2026-2030........... 244,835 244,835
5.45% - 6.40% 2031-2035........... 399,565 399,565
5% - 8% 2037................ 15,001 15,001
MEDIUM-TERM NOTES
7.10% - 7.13% 1997................. 100,000 --
7.15% - 7.18% 2023................. 40,500 40,500
8.10% - 8.16% 2009................. 60,000 60,000
---------- ----------
Total First and Refunding Mortgage
Bonds............................... $4,610,811 $4,824,811
========== ==========
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31,
--------------------------
INTEREST RATES DUE 1995 1994
- ----------------- ---- ---------- ----------
(THOUSANDS OF DOLLARS)
DEBENTURE BONDS UNSECURED
6% 1998.......................................... $ 18,195 $ 18,195
---------- ----------
Total Debenture Bonds............................................... 18,195 18,195
---------- ----------
Principal Amount Outstanding (note F)............................... 4,629,006 4,843,006
Amounts Due Within One Year (note B)................................ (310,200)
Net Unamortized Discount............................................ (42,738) (46,019)
---------- ----------
Total Long-Term Debt of PSE&G (note G)......................... 4,586,268 4,486,787
---------- ----------
EDHI
CAPITAL (note C)
Senior notes
9.875% - 10.05% 1998.......................................... 122,500 165,000
Medium-Term Notes
5.65% - 9.55% 1995.......................................... 112,000
9.00% 1996.......................................... 20,000 20,000
5.79% - 5.92% 1997.......................................... 27,000 27,000
9.00% 1998.......................................... 75,000 75,000
8.95% - 9.93% 1999.......................................... 155,000 155,000
6.54% 2000.......................................... 78,000 78,000
---------- ----------
Principal Amount Outstanding (note F)............................... 477,500 632,000
Amounts Due Within One Year (note B)................................ (62,482) (154,405)
Net Unamortized Discount............................................ (901) (1,278)
---------- ----------
Total Long-Term Debt of Capital................................ 414,117 476,317
---------- ----------
FUNDING (note D)
9.54% 1995.......................................... 35,000
9.55% 1996.......................................... 28,000 28,000
6.85% - 9.59% 1997.......................................... 55,000 55,000
9.95% 1998.......................................... 83,000 83,000
7.58% 1999.......................................... 45,000 45,000
---------- ----------
Principal Amount Outstanding (note F)............................... 211,000 246,000
Amounts Due Within One Year (note B)................................ (28,000) (35,000)
---------- ----------
Total Long-Term Debt of Funding................................ 183,000 211,000
---------- ----------
EGDC MORTGAGE NOTES
10.625% - 12.75% 2012 (note F)................................. 6,554 6,686
---------- ----------
Amounts Due Within One Year (note B)................................ (148) (133)
---------- ----------
Total Long-Term Debt of EGDC................................... 6,406 6,553
---------- ----------
Total Long-Term Debt of EDHI................................... 603,523 693,870
---------- ----------
Consolidated Long-Term Debt (note E)......................... $5,189,791 $5,180,657
========== ==========
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTES:
(A) PSE&G's Mortgage, securing the Bonds, constitutes a direct first
mortgage lien on substantially all PSE&G'S property and franchises.
(B) The aggregate principal amounts of mandatory requirements for
sinking funds and maturities for each of the five years following
December 31, 1995 are as follows:
SINKING
FUNDS MATURITIES
---------- ----------------------------------------------
YEAR CAPITAL PSE&G CAPITAL EGDC FUNDING TOTAL
(THOUSANDS OF DOLLARS)
1996.......... $ 42,500 $ -- $ 20,000 $ 148 $ 28,000 $ 90,648
1997........... 42,500 400,000 27,000 166 55,000 524,666
1998........... 37,500 118,195 75,000 184 83,000 313,879
1999........... -- 100,000 155,000 205 45,000 300,205
2000........... -- 400,000 78,000 228 -- 478,228
-------- -------- -------- ----- -------- ---------
$122,500 $1,018,195 $355,000 $ 931 $211,000 $1,707,626
======== ======== ======== ===== ======== ==========
In January 1996 principal amounts of $3.5 million of the above series
and $16.942 million of the 8 3/4% Series HH First and Refunding
Mortgage Bonds were reacquired.
On February 1, 1996 a sinking fund in the principal amount of $1.5
million of the 8 3/4% Series HH First and Refunding Mortgage Bonds
was met. In addition, the remaining principal amounts of $192.5
million of the 8 3/4% Series EE and $130.058 million of the 8 3/4%
Series HH were defeased.
(C) Capital has provided up to $750 million debt financing for EDHI's
businesses on the basis of a net worth maintenance agreement with
Enterprise. Since January 31, 1995, Capital has agreed to limit its
borrowings to no more than $650 million.
(D) Funding provides debt financing for EDHI's businesses other than EGDC
on the basis of unconditional guarantees from EDHI.
(E) At December 31, 1995 and 1994, the annual interest requirement on
long-term debt was $399.8 million and $422.7 million, of which $315.6
million and $335.6 million was the requirement for Bonds. The
embedded interest cost on long-term debt on such date was 7.71% and
7.79%, respectively.
(F) For information concerning fair value of financial instruments, see
Note 8 -- Financial Instruments and Risk Management.
(G) At December 31, 1995 and 1994, PSE&G's annual interest requirement
on long-term debt was $330.5 million and $343.3 million, of which
$315.6 million and $335.6 million, respectively, was the requirement
for Bonds. The embedded interest cost on long-term debt was 7.54%
and 7.59%, respectively.
PSE&G has authorization from the BPU to issue approximately $4.375
billion aggregate amount of additional bonds/MTNs/Preferred
Stock/Monthly Income Preferred Securities through 1997 for refunding
purposes.
SHORT-TERM (Commercial Paper and Loans)
Commercial paper represents unsecured bearer promissory notes sold
through dealers at a discount with a term of nine months or less.
Bank loans represent PSE&G's unsecured promissory notes issued under
informal credit arrangements with various banks and have a term of eleven
months or less.
PSE&G
- -----
1995 1994
1993
------ ------
------
(Millions of
Dollars)
Principal amount outstanding at end of year,
primarily commercial paper...................... $ 567 $ 402
$ 533
Weighted average interest rate for Short-Term
Debt at year-end................................ 5.93% 6.07%
3.34%
PSE&G has authorization from the BPU to issue and have outstanding
not more than $1 billion of its short-term obligations at any one time,
consisting of commercial paper and other unsecured borrowings from banks
and other lenders. This authorization expires January 1, 1997.
PSE&G has a $500 million one year revolving credit agreement expiring
in August 1996 and a $500 million five year revolving credit agreement
expiring in August 2000 with a group of commercial banks each of which
provides for borrowing up to one year. As of December 31, 1995, there was
no short-term debt outstanding under this agreement.
PSE&G has a $50 million uncommitted Line of Credit facility extended
by a bank to primarily support short-term borrowings all of which was
outstanding under this facility on December 31, 1995 and is included in
the table above.
PSE&G had various Lines of Credit facility extended by a bank to
primarily support the issuance of Letters of Credit. As of December 31,
1995, Letters of Credit were issued in the amount of $20.6 million.
Fuelco has a $150 million commercial paper program to finance a
42.49% share of Peach Bottom nuclear fuel, supported by a $150 million
revolving credit facility with a group of banks, which expires in June
1996. PSE&G has guaranteed repayment of Fuelco's respective obligations.
As of December 31, 1995, 1994 and 1993, Fuelco had commercial paper of
$87.7 million, $93.7 million and $108.7 million, respectively, outstanding
under such program, which amounts are included in the table above.
PSCRC has a $30 million revolving credit facility supported by a
PSE&G subscription agreement in an aggregate amount of $30 million which
terminates on March 7, 1996. PSCRC is presently in the process of
negotiating a one year extension for this facility. As of December 31,
1995, PSCRC had $30 million outstanding under this facility, which amount
is included in the table above.
PSE&G has entered into standby financing arrangements with a bank
totaling $61 million. These facilities support tax-exempt multi-mode
financings done through the New Jersey Economic Development Authority and
the York County (Pennsylvania) Industrial Development Authority. As of
December 31, 1995, no amounts were outstanding under such arrangements.
EDHI
- ----
1995 1994 1993
------ ------ ------
(Millions of Dollars)
Principal amount outstanding at end of year....... $ 182 $ 90 $ 45
Weighted average interest rate for Short-Term
Debt at year-end................................ 6.26% 5.97%
3.47%
At December 31, 1995, Funding had a $225 million commercial paper program
supported by a direct pay commercial bank letter of credit and revolving credit
facility and a $225 million revolving credit facility, each of which expires in March
1998. At December 31, 1995, there was $100 million outstanding under this agreement.
ENTERPRISE
- ----------
At December 31, 1995, 1994 and 1993, Enterprise had a $25 million line of credit
with a bank. At December 31, 1995, 1994 and 1993, Enterprise had no borrowings under
this line.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 7. LONG-TERM INVESTMENTS
Long-Term Investments are primarily those of EDHI. A summary of
Long-Term Investments is as follows:
1995 1994
------ ------
(MILLIONS OF DOLLARS)
Lease Agreements (see Note 11 -
Leasing Activities):
Leveraged Leases...................... $ 845 $ 789
Direct-Financing Leases............... 35 76
Other Leases.......................... 6 6
------ ------
Total............................ 886 871
------ ------
Partnerships:
General Partnerships.................. 177 168
Limited Partnerships.................. 522 437
------ ------
Total............................ 699 605
------ ------
Corporate Joint Ventures.................. 49 26
Securities................................ 76 75
Valuation Allowances...................... (21) (17)
Other Investments......................... 133 66
------ ------
Total Long-Term Investments...... $1,822 $1,626
====== ======
PSRC's leveraged leases are reported net of principal and interest
on nonrecourse loans, unearned income and deferred tax credits. Income
and deferred tax credits are recognized at a level rate of return from
each lease during the periods in which the net investment is positive.
Partnership investments are those of PSRC, EGDC and CEA and are
undertaken with other investors. PSRC is a limited partner in various
partnerships and is committed to make investments from time to time
upon the request of the respective general partners. As of December 31,
1995, $58 million remained as PSRC's unfunded commitment subject to
call.
PSRC has invested in securities and limited partnerships investing
in securities, which are recorded at fair value. Realized investment
gains and losses on the sale of investment securities are determined
utilizing the specific cost identification method. (See Note 8 --
Financial Instruments and Risk Management.)
As of December 31, 1995 and 1994, EDHI's long-term investments
aggregated $1.7 billion and $1.6 billion, respectively, and its
property, plant and equipment (net of accumulated depreciation and
amortization and valuation allowances) aggregated $.7 billion. As of
December 31, 1995 and December 31, 1994, EDHI comprised 15% of
Enterprise's assets.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
Enterprise's operations give rise to exposure to market risks from
changes in crude oil and natural gas prices, interest rates, foreign
exchange rates and security prices of investments. Enterprise's policy
is to use derivatives for the purpose of managing market risk
consistent with its business plans and prudent practices. Enterprise
does not hold or issue financial instruments for trading purposes.
The notional amounts of derivatives summarized below do not
represent amounts exchanged by the parties and, thus, are not a measure
of the exposure of Enterprise through its use of derivatives. The
amounts exchanged, under the terms of the derivatives, are calculated
on the basis of the notional amounts. Enterprise limits its exposure
to credit-related losses in the event of nonperformance by
counterparties by limiting its counterparties to those with high credit
ratings.
Natural Gas and Crude Oil Hedging
EDC sold natural gas futures contracts outstanding at December 31,
1995 and 1994 which hedged 21,250,000 mmbtu and 10,650,000 mmbtu,
respectively. Such amounts represented approximately 26% and 13% of
EDC's anticipated domestic natural gas production in 1996 and 1995,
respectively, at average sales prices of $1.93 per mmbtu and $1.95 per
mmbtu, respectively.
At December 31, 1995, EDC sold crude oil futures contracts
outstanding which hedged 1.5 million barrels of oil representing
approximately 38% of EDC's anticipated domestic oil production in 1996
at an average price of $17.74 per barrel.
The deferred unrealized gains (losses) at December 31, 1995 and
1994 related to EDC's futures contracts were ($5.1) million and $2.6
million, respectively.
Through December 31, 1995 and 1994, USEP entered into swaps for
future contracts to buy 4,970,000 mmbtu and 2,850,000 mmbtu of natural
gas related to fixed-price sales commitments. Such swaps hedged
approximately 54% and 73% of sales commitments at December 31, 1995 and
1994 at average prices of $1.78 and $1.94 per mmbtu, respectively.
USEP had deferred unrealized gains of $3.1 million at December 31, 1995
and unrealized losses of $.7 million at December 31, 1994.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Interest Rate Swap
Capital entered into an interest rate swap in December, 1990 to
allow EDHI to borrow at floating rates and effectively swap them into
fixed rates. The interest differential to be received or paid under the
interest rate swap agreement is accrued over the life of the agreement
as an adjustment to the interest expense of the related borrowing. The
swap expired on December 11, 1995.
1995 1994
--------- ---------
(Thousands of Dollars)
Pay-fixed swap
Notional amount.................... $100,000 $100,000
Pay rate........................... 8.0% 8.0%
Average receive rate............... 6.4% 4.1%
Year-end receive rate.............. --% 6.8%
Foreign Exchange
During 1994, PSRC entered into a forward purchase contract for
foreign currency to hedge an EDC firm purchase commitment denominated
in pound sterling. The EDC commitment related to the acquisition of
Industrial Scotland Energy Limited (ISE) for approximately 21 million
pounds. The realized gain of approximately $800 thousand on the
forward purchase contract for foreign currency was used to reduce the
net acquisition cost allocated to ISE's assets upon completion of the
acquisition in June 1994.
Currently, substantially all of Enterprise's foreign revenues and
expenses are denominated in U.S. dollars.
Security Swap
During 1994, PSRC entered into two agreements to swap portions of
its ownership interest in certain equity securities, held in a
partnership, to the S&P 500 return. The purpose of the swaps was to
minimize PSRC's exposure to the potential price volatility of such
equity securities. The agreements had respective notional amounts of
$17.6 million and $12.9 million.
The aggregate notional amounts swapped and the year end unrealized
gain during 1994 for these two agreements were $30.5 million and $3.8
million, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In March 1995, the equity securities, in which PSRC had an
ownership interest, were exchanged for equity securities of another
entity. Consequently, PSRC terminated the security swap and realized
a pre-tax gain of $3.5 million which was offset by the reversal of the
$3.8 million unrealized gain at year end 1994.
Fair Value of Financial Instruments
The estimated fair value was determined using the market
quotations or values of securities with similar terms, credit ratings,
remaining maturities and redemptions at the end of 1995 and 1994,
respectively.
1995 1994
------------------------ ------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
---------- ---------- ---------- ----------
(Thousands of Dollars)
Long-Term Debt:
EDHI.................................... $ 603,523 730,000 $ 884,686 $ 930,000
PSE&G................................... 4,629,006 4,828,008 4,843,006 4,500,000
Preferred Securities Subject to
Mandatory Redemption:
PSE&G Cumulative Preferred Securities... 150,000 156,000 150,000 145,900
Monthly Income Preferred Securities..... 210,000 225,300 150,000 158,300
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 9. CASH AND CASH EQUIVALENTS
The December 31, 1995 and 1994 balances consist primarily of working funds
and highly liquid marketable securities (commercial paper) with a maturity of
three months or less.
NOTE 10. FEDERAL INCOME TAXES
A reconciliation of reported Net Income with pretax income and of Federal
income tax expense with the amount computed by multiplying pretax income by the
statutory Federal income tax rate of 35% is as follows:
1995 1994 1993
---------- -------- --------
(THOUSANDS OF DOLLARS)
Net Income......................................... $ 662,323 $ 679,033 $600,933
Preferred securities dividend requirements......... 34,236 40,467 38,114
SFAS 109 Cumulative Effect......................... -- -- (5,414)
---------- -------- --------
Subtotal...................................... 696,559 719,500 633,633
---------- -------- --------
Federal income taxes:
Operating income:
Current provision................................ 183,268 162,521 151,208
Provision for deferred income taxes -- net(A).... 192,648 173,327 186,256
Investment tax credits -- net.................... (21,919) (23,297) (23,784)
---------- -------- --------
Total included in operating income................. 353,997 312,551 313,680
Miscellaneous other income:
Current provision................................ (9,897) (8,186) (14,340)
Provision for deferred income taxes(A)........... 9,816 10,422 9,815
SFAS 90 deferred income taxes(A)................... 2,161 2,530 2,948
---------- -------- --------
Total Federal income tax provisions........... 356,077 317,317 312,103
---------- -------- --------
Pretax income...................................... $1,052,636 $1,036,817 $945,736
========== ======== ========
Reconciliation between total Federal income tax provisions and tax computed
at the statutory tax rate on pretax income:
1995 1994 1993
-------- -------- --------
(THOUSANDS OF DOLLARS)
Tax computed at the statutory rate................. $ 368,423 $362,887 $331,008
-------- -------- --------
Increase (decrease) attributable to flow through of
certain tax adjustments:
Depreciation.................................. 16,257 (4,597) 3,347
Amortization of investment tax credits........... (21,919) (23,297) (23,784)
Other............................................ (6,684) (17,676) 1,532
-------- -------- --------
Subtotal...................................... (12,346) (45,570) (18,905)
-------- -------- --------
Total Federal income tax provisions........... $(356,077) $317,317 $312,103
======== ======== ========
Effective Federal income tax rate.................. 33.8% 30.6% 33.0%
(A) The provision for deferred income taxes represents the tax effects of the
following items:
1995 1994 1993
-------- -------- --------
(THOUSANDS OF DOLLARS)
Deferred Credits:
Additional tax depreciation and amortization..... $174,190 $109,106 $112,814
Leasing Activities............................... 64,567 60,129 34,958
Property Abandonments............................ (7,411) (6,606) (6,632)
Oil and Gas Property Write-Down.................. (2,451) (2,451) (2,451)
Deferred fuel costs -- net....................... (3,601) 39,361 63,330
Other............................................ (20,669) (13,260) (3,000)
-------- -------- --------
Total......................................... $204,625 $186,279 $199,019
======== ======== ========
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Between the years 1987 and 1994, Enterprise's Federal alternative
minimum tax (AMT) liability exceeded its regular Federal income tax
liability. This excess can be carried forward indefinitely to offset
regular income tax liability in future years. Enterprise commenced using
these AMT credits in 1995 and expects to continue using them in future
years as regular tax liability exceeds AMT. As of December 31, 1995, 1994
and 1993, Enterprise had AMT credits of $203 million, $256 million and
$247 million, respectively.
Since 1986, Enterprise has filed a consolidated Federal income tax
return on behalf of itself and its subsidiaries. Prior to 1986, PSE&G
filed consolidated tax returns. In March, 1992, the Internal Revenue
Service (IRS) issued a Revenue Agent's Report (RAR) following completion
of examination of PSE&G's consolidated tax return for 1985 and
Enterprise's consolidated tax returns for 1986 and 1987, proposing various
adjustments for such years which would increase Enterprise's consolidated
Federal income tax liability by approximately $121 million, exclusive of
interest and penalties, of which approximately $118 million is
attributable to PSE&G. Interest after taxes on these proposed adjustments
is currently estimated to be approximately $119 million as of December 31,
1995 and will continue to accrue at the Federal rate for large corporate
underpayments, currently 11% annually.
The most significant of these proposed adjustments relates to the IRS
contention that PSE&G's Hope Creek nuclear unit is a partnership with a
short 1986 taxable year. In addition, the IRS contends that the tax
in-service date of that unit is four months later than the date claimed by
PSE&G. In June 1992, Enterprise and PSE&G filed a protest with the IRS
disagreeing with certain of the proposed adjustments (including those
related to Hope Creek) contained in the RAR for taxable years 1985 through
1987 and continue to contest these issues. Any tax adjustments resulting
from the RAR would reduce Enterprise's and PSE&G's respective deferred
credits for accumulated deferred income taxes. While PSE&G believes that
assessments attributable to it are generally recoverable from its
customers in rates, no assurances can be given as to what regulatory
treatment may be afforded by the BPU.
On January 1, 1993, Enterprise adopted SFAS 109 without restating
prior years' financial statements which resulted in Enterprise recording
a $5.4 million cumulative effect increase in its net income. Under SFAS
109, deferred taxes are provided at the enacted statutory tax rate for all
temporary differences between the financial statement carrying amounts and
the tax bases of existing assets and liabilities irrespective of the
treatment for rate-making purposes. Since management believes that it is
probable that the effects of SFAS 109 on PSE&G, principally the
accumulated tax benefits that previously have been treated as a
flow-through item to customers, will be recovered from utility customers
in the future, an offsetting regulatory asset was established. As of
December 31, 1995, PSE&G had recorded a deferred tax liability and an
offsetting regulatory asset of $769 million representing the future
revenue expected to be recovered through rates based upon established
regulatory practices which permit recovery of current taxes payable. This
amount was determined using the 1995 Federal income tax rate of 35%.
SFAS 109
The following is an analysis of accumulated deferred income taxes:
ACCUMULATED DEFERRED INCOME TAXES 1995 1994
---------------------------------------- ---------- ----------
(THOUSANDS OF DOLLARS)
Assets:
Current (net)...................................... $ 27,571 $ 25,311
Non-Current:
Unrecovered Investment Tax Credits............ 129,713 136,402
Nuclear Decommissioning....................... 25,241 25,082
Hope Creek Cost Disallowance.................. -- 10,127
Construction Period Interest and Taxes........ 17,199 15,913
Vacation Pay.................................. 6,681 6,822
AMT Credit.................................... 202,655 255,828
Real Estate Impairment........................ 5,213 20,932
Other......................................... 4,107 6,863
---------- ----------
Total Non-Current........................ $ 390,809 $ 477,969
---------- ----------
Total Assets............................. $ 418,380 $ 503,280
========== ==========
Liabilities:
Non-Current:
Plant Related Items........................... $2,370,830 $2,268,688
Leasing Activities............................ 616,914 580,415
Property Abandonments......................... 21,469 26,971
Oil and Gas Property Write-Down............... 13,061 14,925
Deferred Electric Energy & Gas Costs.......... 56,283 59,884
Unamortized Debt Expense...................... 36,945 37,599
Taxes Recoverable Through Future Rates (net).. 262,625 270,684
Other......................................... 107,302 124,193
---------- ----------
Total Non-Current........................ $3,485,429 $3,383,359
---------- ----------
Total Liabilities........................ $3,485,429 $3,383,359
========== ==========
Summary -- Accumulated Deferred Income Taxes
Net Current Assets............................... $ 27,571 $ 25,311
Net Deferred Liability........................... $3,094,620 $2,905,390
---------- ----------
Total.................................... $3,067,049 $2,880,079
========== ==========
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 11. LEASING ACTIVITIES
As Lessee
The Consolidated Balance Sheets include assets and related
obligations applicable to capital leases under which PSE&G is a
lessee. The total amortization of the leased assets and interest on
the lease obligations equals the net minimum lease payments included
in rent expense for capital leases.
Capital leases of PSE&G relate primarily to its corporate
headquarters and other capital equipment. Certain of the leases
contain renewal and purchase options and also contain escalation
clauses.
Enterprise and its other subsidiaries are not lessees in any
capitalized leases.
Utility plant includes the following amounts for capital leases
at December 31:
1995 1994
------- -------
(THOUSANDS OF DOLLARS)
Common Plant............................................. $58,610 $58,610
Less: Accumulated Amortization........................... 5,499 4,840
------- -------
Net Assets under Capital Leases.......................... $53,111 $53,770
======= =======
Future minimum lease payments for noncancelable capital and operating
leases at December 31, 1995 were:
CAPITAL OPERATING
LEASES LEASES
------- ---------
(THOUSANDS OF DOLLARS)
1996..................................................... 13,174 14,616
1997..................................................... 13,175 12,580
1998..................................................... 13,176 8,638
1999..................................................... 13,177 6,517
2000..................................................... 12,834 4,449
Later Years.............................................. 189,229 12,998
-------- --------
Minimum Lease Payments................................... 254,765 $ 59,798
========
Less: Amount representing estimated executory costs,
together with any profit thereon, included in
minimum lease payments............................. 126,029
--------
Net minimum lease payments............................... 128,736
Less: Amount representing interest....................... 75,625
--------
Present value of net minimum lease payments(A)........... $ 53,111
========
(A) Reflected in the Consolidated Balance Sheets for 1995 and 1994 were
Capital Lease Obligations of $53.111 million and $53.770 million which
includes Capital Lease Obligations due within one year of $739 thousand
and $659 thousand, respectively.
The following schedule shows the composition of rent expense included
in Operating Expenses:
FOR THE YEARS ENDED DECEMBER 31,
--------------------------------
1995 1994 1993
------- ------- -------
(THOUSANDS OF DOLLARS)
Interest on Capital Lease Obligations................. $ 6,084 $ 6,156 $ 6,074
Amortization of Utility Plant under Capital Leases.... 659 588 513
------- ------- -------
Net minimum lease payments relating to Capital
Leases.............................................. 6,743 6,744 6,587
Other Lease payments.................................. 27,219 28,447 22,132
------- ------- -------
Total Rent Expense.................................... $33,962 $35,191 $28,719
======= ======= =======
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As Lessor
PSRC's net investments in leveraged and direct financing leases are composed of
the following elements:
DECEMBER 31, 1995 DECEMBER 31, 1994
---------------------------------- ----------------------------------
(MILLIONS OF DOLLARS)
DIRECT DIRECT
LEVERAGED FINANCING LEVERAGED FINANCING
LEASES LEASES TOTAL LEASES LEASES TOTAL
--------- --------- ------- --------- --------- -------
Lease rents receivable..... $ 1,031 $ 39 $ 1,070 $ 990 $ 92 $ 1,082
Estimated residual value... 635 8 643 622 13 635
-------- ------- ------- -------- ------- -------
1,666 47 1,713 1,612 105 1,717
Unearned and deferred income (821) (12) (833) (823) (29) (852)
-------- ------- ------- -------- ------- -------
Total investments...... 845 35 880 789 76 865
Deferred taxes.............. (405) (11) (416) (333) (20) (353)
-------- ------- ------- -------- ------- -------
Net investments........ $ 440 $ 24 $ 464 $ 456 $ 56 $ 512
======== ======= ======= ======== ======= =======
PSRC's other capital leases are with various regional, state and city authorities for transportation
equipment and aggregated $6 million as of December 31, 1995 and 1994.
During 1995, PSRC converted two Airbus A-300 aircraft under direct-finance leases to operating
leases. As of December 31, 1995, such aircraft had a net asset value of $11 million. On January 31, 1996,
the aircraft were sold for an amount approximating their net asset value.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 12. COMMITMENTS AND CONTINGENT LIABILITIES
Nuclear Performance Standard
The BPU has established its NPS for nuclear generating stations
owned by New Jersey electric utilities, including the five nuclear
units in which PSE&G has an ownership interest: Salem Units 1 and 2
- -- 42.59%; Hope Creek -- 95%; and Peach Bottom Units 2 and 3 -- 42.49%.
PSE&G operates Salem and Hope Creek, while Peach Bottom is operated by
PECO Energy, Inc. (PECO).
The penalty/reward under the NPS is a percentage of replacement
power costs. (See table below.)
CAPACITY FACTOR RANGE REWARD PENALTY
- -------------------------------------------------- ------ -------
Equal to or greater than 75%......................... 30% --
Equal to or greater than 65% and less than 75%....... None None
Equal to or greater than 55% and less than 65%....... -- 30%
Equal to or greater than 45% and less than 55%....... -- 40%
Equal to or greater than 40% and less than 45%....... -- 50%
Below 40%............................................ BPU Intervenes
Under the NPS, the capacity factor is calculated annually using
maximum dependable capability of the five nuclear units in which PSE&G
owns an interest. This method takes into account actual operating
conditions of the units.
While the NPS does not specifically have a gross negligence
provision, the BPU has indicated that it would consider allegations of
gross negligence brought upon a sufficient factual basis. A finding of
gross negligence could result in penalties other than those prescribed
under the NPS. During 1995, the five nuclear units in which PSE&G has
an ownership interest aggregated a 62% combined capacity factor which
resulted in a penalty for 1995 of approximately $3.5 million. On
January 16, 1996, PSE&G filed its Alternative Rate Plan with the BPU
which proposes the elimination of the NPS. See Note 2.
Based upon current projections and assumptions regarding PSE&G's
five nuclear units during 1996, including the return of Hope Creek to
service in early March, the return of Salem 2 in the third quarter and
the continued outage of Salem 1 for the remainder of the year, the 1996
aggregate capacity factor would be approximately 57%, which would
result in a penalty ranging from $11 to $12 million. Both of the Salem
units are currently out of service and their return dates are subject
to completion of testing, analysis, repair activity and NRC concurrence
that they are prepared to restart. Restart of Salem 1, which had
originally been scheduled for the second quarter of 1996, will be
delayed for a substantial period as a result of the ongoing steam
generator inspection and analysis. Salem 2, which is also undergoing
steam generator inspection and analysis is still scheduled to return
to service in the third quarter of 1996. The inability to successfully
return these units to continuous, safe operation could have a material
effect on the financial position, results of operation and net cash
flows of Enterprise and PSE&G.
Certain of the owners of Salem have indicated that they may seek
to hold PSE&G responsible for their share of costs of the current
outage. PSE&G cannot predict what actions, if any, may be taken.
Nuclear Insurance Coverages and Assessments
PSE&G's insurance coverages and maximum retrospective assessments
for its nuclear operations are as follows:
PSE&G MAXIMUM
TOTAL ASSESSMENTS
SITE FOR A SINGLE
TYPE AND SOURCE OF COVERAGES COVERAGES INCIDENT
- ------------------------------------- --------- -------------
(MILLIONS OF DOLLARS)
Public Liability:
American Nuclear Insurers........... $ 200.0 $ --
Indemnity(A)........................ 8,720.3 210.2
-------- --------
$8,920.3 (B) $ 210.2
-------- --------
Nuclear Worker Liability:
American Nuclear Insurers(C)........ $ 200.0 $ 8.1
-------- --------
Property Damage:
Nuclear Mutual Limited.............. $ 500.0 $ 9.2
Nuclear Electric Insurance
Ltd. (NEIL II)..................... 1,400.0 8.3(D)
Nuclear Electric Insurance
Ltd. (NEIL III).................... 850.0 9.2
-------- --------
$2,750.0 $ 26.7
-------- --------
Replacement Power:
Nuclear Electric Insurance
Ltd (NEIL I)....................... $ 3.5 (E) $ 11.4
(A) Retrospective premium program under the Price-Anderson liability
provisions of the Atomic Energy Act of 1954, as amended (Price-
Anderson). Subject to retrospective assessment with respect to
loss from an incident at any licensed nuclear reactor in the
United States. Assessment adjusted for inflation effective August
20, 1993.
(B) Limit of liability for each nuclear incident under Price-
Anderson.
(C) Industry aggregate limit representing the potential liability from
workers claiming exposure to the hazard of nuclear radiation. This
policy includes automatic reinstatements up to an aggregate of
$200 million, thereby providing total coverage of $400 million.
This policy does not increase PSE&G's obligation under Price-
Anderson.
(D) In the event of a second industry loss triggering NEIL II -
coverage, the maximum retrospective premium assessment can
increase to $18.5 million.
(E) Represents limit of coverage available to co-owners of Salem and
Hope Creek, for each plant. Each co-owner purchases its own
policy. PSE&G is currently covered for its percent ownership
interest of this limit for each plant.
Price-Anderson sets the "limit of liability" for claims that could
arise from an incident involving any licensed nuclear facility in the
nation. The "limit of liability" is based on the number of licensed
nuclear reactors and is adjusted at least every five years based on the
Consumer Price Index. The current "limit of liability" is $8.9 billion.
All utilities owning a nuclear reactor, including PSE&G, have provided
for this exposure through a combination of private insurance and
mandatory participation in a financial protection pool as established
by Price-Anderson. Under Price- Anderson, each party with an ownership
interest in a nuclear reactor can be assessed its share of $79.3
million per reactor per incident, payable at $10 million per reactor
per incident per year. If the damages exceed the "limit of liability,"
the President is to submit to Congress a plan for providing additional
compensation to the injured parties. Congress could impose further
revenue raising measures on the nuclear industry to pay claims. PSE&G's
maximum aggregate assessment per incident is $210.2 million (based on
PSE&G's ownership interests in Hope Creek, Peach Bottom and Salem) and
its maximum aggregate annual assessment per incident is $26.5 million.
Further, a recent decision by the U.S. Court of Appeals for the
Third Circuit, not involving PSE&G, held that the Price Anderson Act
did not preclude awards based on state law claims for punitive damage.
PSE&G is a member of two industry mutual insurance companies;
Nuclear Mutual Limited (NML), and Nuclear Electric Insurance Limited
(NEIL). NML provides the primary property insurance at Salem and Hope
Creek. NEIL provides excess property insurance through its NEIL II and
NEIL III policies and replacement power coverage through its NEIL I
policy. Both companies may make retrospective premium assessments in
case of adverse loss experience. PSE&G's maximum potential liabilities
under these assessments are included in the table and notes above.
Certain of the policies also provide that the insurer may suspend
coverage with respect to all nuclear units on a site without notice if
the NRC suspends or revokes the operating license for any unit on a
site, issues a shutdown order with respect to such unit or issues a
confirmatory order keeping such unit down. All coverages at Salem and
Hope Creek remain fully in effect.
Construction and Fuel Supplies
PSE&G has substantial commitments as part of its ongoing
construction program which include capital requirements for nuclear
fuel. PSE&G's construction program is continuously reviewed and
periodically revised as a result of changes in economic conditions,
revised load forecasts, changes in the scheduled retirement dates of
existing facilities, changes in business strategies, site changes, cost
escalations under construction contracts, requirements of regulatory
authorities and laws, the timing of and amount of electric and gas rate
changes and the ability of PSE&G to raise necessary capital. Pursuant
to an electric integrated resource plan (IRP), PSE&G periodically
reevaluates its forecasts of future customers, load and peak growth,
sources of electric generating capacity and demand side management
(DSM) to meet such projected growth, including the need to construct
new electric generating capacity. The IRP takes into account
assumptions concerning future demands of customers, effectiveness of
conservation and load management activities, the long-term condition
of PSE&G's plants, capacity available from electric utilities and other
suppliers and the amounts of co-generation and other non-utility
capacity projected to be available.
Based on PSE&G's construction program, construction expenditures
are expected to aggregate approximately $2.8 billion, which includes
$428 million for nuclear fuel and $84 million of Allowance for Funds
used During Construction (AFDC) during the years 1996 through 2000. The
estimate of construction requirements is based on expected project
completion dates and includes anticipated escalation due to inflation
of approximately 3%, annually. Therefore, construction delays or higher
inflation levels could cause significant increases in these amounts.
PSE&G expects to generate internally the funds necessary to satisfy its
construction expenditures over the next five years, assuming adequate
and timely recovery of costs, as to which no assurances can be given.
In addition, PSE&G does not presently anticipate any difficulties in
obtaining sufficient sources of fuel for electric generation or
adequate gas supplies during the years 1996 through 2000.
Hazardous Waste
Certain Federal and State laws authorize the United States
Environmental Protection Agency (EPA) and the New Jersey Department of
Environmental Protection (NJDEP), among other agencies, to issue orders
and bring enforcement actions to compel responsible parties to take
investigative and remedial actions at any site that is determined to
present an imminent and substantial danger to the public or the
environment because of an actual or threatened release of one or more
hazardous substances. Because of the nature of PSE&G's business,
including the production of electricity, the distribution of gas and,
formerly, the manufacture of gas, various by-products and substances
are or were produced or handled which contain constituents classified
as hazardous. PSE&G generally provides for the disposal or processing
of such substances through licensed independent contractors. However,
these statutory provisions impose joint and several responsibility
without regard to fault on all responsible parties, including the
generators of the hazardous substances, for certain investigative and
remediation costs at sites where these substances were disposed of or
processed. PSE&G has been notified with respect to a number of such
sites and the remediation of these potentially hazardous sites is
receiving greater attention from the government agencies involved.
Generally, actions directed at funding such site investigations and
remediation include all suspected or known responsible parties. PSE&G
does not expect its expenditures for any such site to have a material
effect on its financial position, results of operations or net cash
flows.
PSE&G Manufactured Gas Plant Remediation Program
In 1988, NJDEP notified PSE&G that it had identified the need for
PSE&G, pursuant to a formal arrangement, to systematically investigate
and, if necessary, resolve environmental concerns extant at PSE&G's
former manufactured gas plant sites. To date, NJDEP and PSE&G have
identified 38 former gas plant sites. PSE&G is currently working with
NJDEP under a program to assess, investigate and, if necessary,
remediate environmental concerns at these sites (Remediation Program).
The Remediation Program is periodically reviewed and revised by PSE&G
based on regulatory requirements, experience with the Remediation
Program and available technologies. The cost of the Remediation Program
cannot be reasonably estimated, but experience to date indicates that
costs of at least $20 million per year could be incurred over a period
of more than 30 years and that the overall cost could be material to
PSE&G's financial position, results of operations or net cash flows.
Costs incurred through December 31, 1995 for the Remediation
Program amounted to $64.6 million, net of certain insurance proceeds.
In addition, at December 31, 1995, PSE&G's estimated liability for
remediation costs through 1998 aggregated $96.3 million.
In accordance with a Stipulation approved by the BPU in 1992, PSE&G
is recovering through its LEAC over a six-year period $32 million of
its actual remediation costs to reflect costs incurred through
September 30, 1992. As of December 31, 1995, PSE&G has recovered $27.8
million of the $32 million of such costs. PSE&G is expected to recover
the balance of $4.2 million in its currently filed LGAC period ending
in 1996.
NOTE 13. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
On January 1, 1993, Enterprise and PSE&G adopted SFAS 106 which
requires that the expected cost of employees' postretirement health
care and insurance benefits be charged to expense during the years in
which employees render service. PSE&G elected to amortize, over 20
years, its unfunded obligation of $609.3 million at January 1, 1993.
The following table discloses the significant components of the net
periodic postretirement benefit obligation:
DECEMBER 31,
---------------------------
NET PERIODIC POSTRETIREMENT BENEFIT OBLIGATION 1995 1994 1993
- ---------------------------------------------- ------- ------- -------
(MILLIONS)
Service cost................................. $ 8.5 $ 11.1 $ 11.7
Interest on accumulated postretirement
obligation................................. 48.2 45.4 44.4
Amortization of transition obligation........ 30.5 30.5 30.5
Amortization of Net (Gain)/Loss (a).......... (3.8) -- --
Deferral of current expense.................. (50.7) (57.8) (58.6)
------ ------ -------
Annual net expense...................... $ 32.7 $ 29.2 $ 28.0
====== ====== =======
(a) Reflects change in Plan Assumptions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The discount rate used in determining the PSE&G net periodic
postretirement benefit cost was 8.50% and 7.25% for 1995 and 1994,
respectively.
A one-percentage-point increase in the assumed health care cost
trend rate for each year would increase the aggregate of the service
and interest cost components of net periodic postretirement health care
cost by approximately $2.6 million, or 5.6%, and increase the
accumulated postretirement benefit obligation as of December 31, 1995
by $34.8 million, or 5.9%.
The assumed health care cost trend rates used in measuring the
accumulated postretirement benefit obligation in 1995 were: medical
costs for pre-age sixty-five retirees -- 13.0%, medical costs for
post-age sixty-five retirees -- 9.0% and dental costs -- 7.0%; such
rates are assumed to gradually decline to 5.0%, 5.0% and 5.0%,
respectively, in 2011. The medical costs above include a provision for
prescription drugs.
In its 1992 base rate case, PSE&G requested full recovery of the
costs associated with postretirement benefits other than pensions
(OPEB) on an accrual basis, in accordance with SFAS 106. The BPU's
December 31, 1992 base rate order provided that (1) PSE&G's
pay-as-you-go basis OPEB costs will continue to be included in cost of
service and will be recoverable in base rates on a pay-as-you-go basis;
(2) prudently incurred OPEB costs, that are accounted for on an accrual
basis in accordance with SFAS 106, will be recoverable in future rates;
(3) PSE&G should account for the differences between its OPEB costs on
an accrual basis and the pay-as-you-go basis being recovered in rates
as a regulatory asset; and (4) the issue of cash versus accrual
accounting will be revisited and in the event that FASB or the SEC
requires the use of accrual accounting for OPEB costs for rate-making
purposes, the regulatory asset will be recoverable, through rates, over
an appropriate amortization period.
Accordingly, PSE&G is accounting for the differences between its
SFAS 106 accrual cost and the cash cost currently recovered through
rates as a regulatory asset. OPEB costs charged to expenses during 1995
were $32.6 million and accrued OPEB costs deferred were $50.7 million.
The amount of the unfunded liability, at December 31, 1995, as shown
below, is $717.9 million and funding options are currently being
explored. The primary effect of adopting SFAS 106 on Enterprise's and
PSE&G's financial reporting is on the presentation of their financial
positions with minimal effect on their results of operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During January 1993 and subsequent to the receipt of the Order, the
FASB's Emerging Issues Task Force (EITF) concluded that deferral of
such costs is acceptable, provided regulators allow SFAS 106 costs in
rates within approximately five years of the adoption of SFAS 106 for
financial reporting purposes, with any cost deferrals recovered in
approximately twenty years. In accordance with the Alternative Rate
Plan filed, PSE&G expects full SFAS 106 recovery in accordance with the
EITF's view of such standard and believes that it is probable that any
deferred costs will be recovered from utility customers within such
twenty-year time period. As of December 31, 1995, PSE&G has deferred
$167.2 million of such costs. However, if recovery of SFAS 106 costs
is not approved by the BPU , the impact on the financial position and
results of operations would be material.
In accordance with SFAS 106 disclosure requirements, a
reconciliation of the funded status of the plan is as follows:
DECEMBER 31,
----------------------
1995 1994
-------- --------
(MILLIONS)
Accumulated postretirement benefit obligation:
Retirees................................. $(444.6) $(379.2)
Fully eligible active plan participants.. (52.9) (45.7)
Other active plan participants........... (220.4) (161.0)
------- -------
Total................................ (717.9) (585.9)
Plan assets at fair value................ -- --
------- -------
Accumulated postretirement benefit
obligation in excess of plan assets..... (717.9) (585.9)
Unrecognized net (gain)/loss from past
experience different from that assumed
And from changes in assumptions......... 32.8 (78.8)
Unrecognized prior service cost.......... -- --
Unrecognized transition obligation....... 517.9 548.3
------- -------
Accrued postretirement obligation........ $(167.2) $(116.4)
======= =======
The discount rate used in determining the accumulated postretirement
benefit obligation as of December 31, 1995 was 7.25% and 8.50% for 1995
and 1994, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 14. PENSION PLAN
The discount rates, expected long-term rates of return on assets and
average compensation growth rates used in determining the Pension
Plan's funded status and net pension cost as of December 31, 1995 and
1994 were as follows:
1995 1994
------ ------
Funded Status:
- -------------
Discount Rate used to Determine Benefit
Obligations................................. 7 1/4% 8-1/2%
Average Compensation Growth to Determine
Benefit Obligations...................... 4.5% 4.5%
Net Pension Cost:
- ----------------
Discount Rate............................... 8.5% 7-1/4%
Expected Long-Term Return on Assets......... 8.5% 8%
Average Compensation Growth................. 4.5% 5.5%
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table shows the Pension Plan's funded status:
DECEMBER 31,
-------------------------
1995 1994
----------- -----------
(THOUSANDS OF DOLLARS)
Actuarial present value of benefit obligations:
Accumulated benefit obligations, including vested benefits
of $1,403,313 in 1995 and $1,151,677 in 1994........... $(1,509,841) $(1,235,930)
Effect of projected future compensation................... (321,545) (261,846)
----------- -----------
Projected benefit obligations............................... (1,831,386) (1,497,776)
Plan assets at fair value, primarily listed equity and debt
securities................................................ 1,533,446 1,270,116
----------- -----------
Projected benefit obligations in excess of plan assets...... (297,940) (227,660)
Unrecognized net gain (loss) from past experience and
effects of changes in assumptions......................... 120,859 32,815
Prior service cost not yet recognized in net pension cost... 110,213 119,783
Unrecognized net obligations being recognized over
16.7 years................................................ 61,287 69,387
----------- -----------
Accrued pension expense..................................... $ (5,581) $ (5,675)
=========== ===========
The net pension cost for the years ending December 31, 1995, 1994 and 1993, include the following
components:
1995 1994 1993
-------- -------- --------
(THOUSANDS OF DOLLARS)
Service cost - benefits earned during year......... $ 37,033 $ 42,904 $ 42,948
Interest cost on projected benefit obligations..... 124,147 108,394 103,118
Return on assets................................... (312,190) 5,022 (166,916)
Net amortization and deferral...................... 222,916 (90,752) 90,958
-------- -------- --------
Total......................................... $ 71,906 $ 65,568 $ 70,108
======== ======== ========
See Note 1 -- Organization and Summary of Significant Accounting Policies.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 15. FINANCIAL INFORMATION BY BUSINESS SEGMENTS
Information related to the segments of Enterprise's business is detailed below:
NONUTILITY
ELECTRIC GAS EDC ACTIVITIES(A) TOTAL
----------- ---------- -------- -------------- --------
(THOUSANDS OF DOLLARS)
FOR THE YEAR ENDED DECEMBER 31, 1995
Operating Revenues...................... $ 4,020,842 $1,686,403 $ 248,002 $ 208,906 $ 6,164,153
Eliminations (Intersegment Revenues).... -- -- -- -- --
----------- ---------- ---------- --------- -----------
Total Operating Revenues................ 4,020,842 1,686,403 248,002 208,906 6,164,153
----------- ---------- ---------- --------- -----------
Depreciation and Amortization........... 503,022 88,092 77,265 5,852 674,231
Operating Income Before Income Taxes.... 1,140,279 178,718 58,654 142,172 1,519,823
Capital Expenditures.................... 545,997 140,153 132,098 8,364 826,612
December 31, 1995
- -----------------
Net Utility Plant....................... 9,651,695 1,535,736 -- -- 11,187,431
Oil and Gas Property, Plant &
Equipment............................. -- -- 608,015 -- 608,015
Other Corporate Assets.................. 2,778,691 589,455 147,822 1,858,654 5,374,622
----------- ---------- ---------- --------- -----------
Total Assets............................ $12,430,386 $2,125,191 $ 755,837 $1,858,654 $17,170,068
=========== ========== ========== ========= ===========
FOR THE YEAR ENDED DECEMBER 31, 1994
Operating Revenues...................... $ 3,739,713 $1,778,528 $ 229,880 $ 187,067 $ 5,935,188
Eliminations (Intersegment Revenues).... -- -- (11,179) (1,566) (12,745)
----------- ---------- ---------- --------- -----------
Total Operating Revenues................ 3,739,713 1,778,528 218,701 185,501 5,922,443
----------- ---------- ---------- --------- -----------
Depreciation and Amortization........... 471,910 79,462 78,567 4,089 634,028
Operating Income Before Income Taxes.... 1,083,155 226,196 39,210 133,590 1,482,151
Capital Expenditures.................... 734,100 153,183 160,296 8,445 1,056,024
December 31, 1994
- -----------------
Net Utility Plant....................... 9,642,177 1,456,068 -- -- 11,098,245
Oil and Gas Property, Plant &
Equipment............................. -- -- 577,913 -- 577,913
Other Corporate Assets.................. 2,589,348 576,806 150,973 1,724,155 5,041,282
----------- ---------- ---------- --------- -----------
Total Assets............................ $12,231,525 $2,032,874 $ 728,886 $1,724,155 $16,717,440
=========== ========== ========== ========= ===========
FOR THE YEAR ENDED DECEMBER 31, 1993
Operating Revenues...................... $ 3,696,114 $1,594,341 $ 278,470 $ 161,650 $ 5,730,575
Eliminations (Intersegment Revenues).... -- -- (20,158) (1,827) (21,985)
----------- ---------- ---------- --------- -----------
Total Operating Revenues................ 3,696,114 1,594,341 258,312 159,823 5,708,590
----------- ---------- ---------- --------- -----------
Depreciation and Amortization........... 441,164 69,375 86,136 4,922 601,597
Operating Income Before Income Taxes.... 1,117,739 173,916 92,162 43,310 1,427,127
Capital Expenditures.................... 738,362 152,012 91,988 2,026 984,388
December 31, 1993
- -----------------
Net Utility Plant....................... 9,451,581 1,352,799 -- -- 10,804,380
Oil and Gas Property, Plant &
Equipment............................. -- -- 506,047 -- 506,047
Other Corporate Assets.................. 2,313,394 866,524 173,390 1,665,921 5,019,229
----------- ---------- ---------- --------- -----------
Total Assets............................ $11,764,975 $2,219,323 $ 679,437 $1,665,921 $16,329,656
=========== ========== ========== ========= ===========
(A) The Nonutility Activities include amounts applicable to Enterprise, the parent corporation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Information related to Property, Plant and Equipment of PSE&G is detailed below:
DECEMBER 31,
---------------------------------------
1995 1994 1993
----------- ----------- -----------
(Thousands of Dollars)
Utility Plant - Original Cost
Electric Plant in Service
Steam Production....................... $ 1,791,010 $ 1,810,674 $ 1,763,253
Nuclear Production..................... 5,992,341 5,931,049 5,873,274
Transmission........................... 1,127,031 1,078,928 1,034,150
Distribution........................... 3,044,830 2,877,862 2,724,202
Other.................................. 1,139,891 647,406 526,015
----------- ----------- ------------
Total Electric Plant in Service.... 13,095,103 12,345,919 11,920,894
----------- ----------- -----------
Gas Plant in Service
Transmission........................... 65,109 62,213 63,395
Distribution........................... 2,250,705 2,131,816 1,993,044
Other.................................. 126,758 124,204 121,402
----------- ----------- -----------
Total Gas Plant in Service......... 2,442,572 2,318,233 2,177,841
----------- ----------- -----------
Common Plant in Service
Capital Leases......................... 58,610 58,610 56,812
General................................ 458,494 486,521 463,473
----------- ----------- -----------
Total Common Plant in Service...... 517,104 545,131 520,285
----------- ----------- -----------
TOTAL......................... $16,054,779 $15,209,283 $14,619,020
=========== =========== ===========
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONCLUDED)
NOTE 16. PROPERTY IMPAIRMENT OF ENTERPRISE GROUP DEVELOPMENT
CORPORATION
As a result of a management review of each property's current value
and the potential for increasing such value through operating and other
improvements, EGDC recorded an impairment in 1993 related to certain of
its properties, including properties upon which EDHI's management
revised its intent from a long-term investment strategy to a hold for
sale status, reflecting such properties on its books at their net
realizable value. This impairment reduced the estimated value of EGDC's
properties by $77.6 million and 1993 net income by $50.5 million, after
tax, or 21 cents per share of Enterprise Common Stock.
NOTE 17. JOINTLY OWNED FACILITIES -- UTILITY PLANT
PSE&G has ownership interests in and is responsible for providing
its share of the necessary financing for the following jointly owned
facilities. All amounts reflect the share of PSE&G's jointly owned
projects and the corresponding direct expenses are included in
Consolidated Statements of Income as operating expenses. (See Note 1 --
Organization and Summary of Significant Accounting Policies.)
OWNERSHIP PLANT IN ACCUMULATED PLANT UNDER
PLANT -- DECEMBER 31, 1995 INTEREST SERVICE DEPRECIATION CONSTRUCTION
- ------------------------------------------------ --------- --------- ------------ ------------
(THOUSANDS OF DOLLARS)
Coal Generating
Conemaugh..................................... 22.50% $ 198,724 $ 38,339 $ 2,401
Keystone...................................... 22.84 119,690 32,800 1,629
Nuclear Generating
Peach Bottom.................................. 42.49 755,504 312,856 21,139
Salem......................................... 42.59 1,055,114 396,795 57,041
Hope Creek.................................... 95.00 4,122,715 1,063,403 13,592
Nuclear Support Facilities.................... Various 179,065 33,754 2,990
Pumped Storage Generating
Yards Creek................................... 50.00 27,246 9,293 2,350
Transmission Facilities......................... Various 121,100 36,266 89
Merrill Creek Reservoir......................... 13.91 37,231 12,111 --
Linden Gas Plant................................ 90.00 15,855 19,388 --
NOTE 18. SELECTED QUARTERLY DATA (UNAUDITED)
The information shown below, in the opinion of Enterprise, includes all
adjustments, consisting only of normal recurring accruals, necessary to a fair
presentation of such amounts. Due to the seasonal nature of the utility
business, quarterly amounts vary significantly during the year.
CALENDAR MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
QUARTER ---------------------- --------------------- ---------------------- ----------------------
ENDED 1995 1994 1995 1994 1995 1994 1995 1994
- -------------------------- ---------- ---------- ---------- ---------- ---------- ----------- ---------- ----------
(THOUSANDS WHERE APPLICABLE)
Operating Revenues........ $1,676,269 $1,795,457 $1,328,784 $1,279,588 $1,492,130 $1,376,199 $1,666,970 $1,471,199
Operating Income.......... $ 334,336 $ 348,948 $ 233,239 $ 252,725 $ 311,528 $ 311,920 $ 278,607 $ 250,500
Net Income................ $ 212,592 $ 230,127 $ 110,667 $ 129,885 $ 186,782 $ 187,178 $ 152,282 $ 131,843
Earnings Per Share of
Common Stock............ $ 0.87 $ 0.94 $ 0.45 $ 0.53 $ 0.76 $ 0.76 $ .62 $ 0.54
Average Shares of Common
Stock Outstanding....... 244,698 243,777 244,698 244,698 244,698 244,698 244,698 244,698
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G
Except as modified below, the Notes to Consolidated Financial
Statements of Enterprise are incorporated herein by reference insofar
as they relate to PSE&G and its subsidiaries:
Note 1. - Organization and Summary of Significant Accounting
Policies
Note 2. - Rate Matters
Note 3. - PSE&G Nuclear Decommissioning and Amortization of
Nuclear Fuel
Note 4.- Schedule of Consolidated Capital Stock and Other
Securities
Note 5. - Deferred Items
Note 6. - Schedule of Consolidated Debt
Note 7. - Long-Term Investments
Note 8. - Financial Instruments and Risk Management
Note 11.- Leasing Activities -- As Lessee
Note 12.- Commitments and Contingent Liabilities
Note 13.- Postretirement Benefits Other Than Pensions
Note 14.- Pension Plan
Note 15.- Financial Information by Business Segments
Note 17.- Jointly Owned Facilities -- Utility Plant
NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Consolidation Policy
The consolidated financial statements include the accounts of PSE&G
and its subsidiaries. All significant intercompany accounts and
transactions have been eliminated in consolidation. Certain
reclassifications of prior years' data have been made to conform with
the current presentation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 9. CASH AND CASH EQUIVALENTS
The December 31, 1995 and 1994 balances consist primarily of working funds.
NOTE 10. FEDERAL INCOME TAXES
A reconciliation of reported Net Income with pretax income and of Federal income tax expense
with the amount computed by multiplying pretax income by the statutory Federal income tax rate of
35% is as follows:
1995 1994 1993
-------- -------- --------
(THOUSANDS OF DOLLARS)
Net Income......................................... $616,964 $659,406 $614,868
-------- -------- --------
Federal income taxes:
Operating income:
Current provision............................. 275,460 230,709 177,314
Provision for deferred income taxes-net(A).... 65,084 83,028 149,884
Investment tax credits -- net................. (19,111) (19,208) (18,408)
-------- -------- --------
Total included in operating income................. 321,433 294,529 308,790
Miscellaneous other income:
Current provision................................ (9,897) (8,186) (15,419)
Provision for deferred income taxes(A)........... 9,816 10,422 9,815
SFAS 90 deferred income taxes(A)................... 2,161 2,530 2,948
-------- -------- --------
Total Federal income tax provisions........... 323,513 299,295 306,134
-------- -------- --------
Pretax income...................................... $940,477 $958,701 $921,002
======== ======== ========
Reconciliation between total Federal income tax provisions and tax computed at the statutory tax
rate on pretax income:
1995 1994 1993
-------- -------- --------
(THOUSANDS OF DOLLARS)
Tax expense at the statutory rate.................. $329,167 $335,546 $322,351
-------- -------- --------
Increase (decrease) attributable to flow-through of
certain tax adjustments:
Depreciation.................................. 16,257 (4,597) 3,347
Amortization of investment tax credits........ (19,111) (19,208) (18,408)
Other......................................... (2,800) (12,446) (1,156)
-------- -------- --------
Subtotal...................................... (5,654) (36,251) (16,217)
-------- -------- --------
Total Federal income tax provisions........... $323,513 $299,295 $306,134
======== ======== ========
Effective Federal income tax rate.................. 34.4% 31.2% 33.2%
(A) The provision for deferred income taxes represents the tax effects of the following items:
1995 1994 1993
-------- -------- --------
(THOUSANDS OF DOLLARS)
Deferred Credits:
Additional tax depreciation and amortization......... $111,193 $ 85,335 $ 92,693
Property Abandonments................................ (7,411) (6,606) (6,632)
Oil and Gas Property Write-Down...................... (2,451) (2,451) (2,451)
Deferred fuel costs-net.............................. (3,601) 39,361 63,330
Other................................................ (20,669) (19,659) 15,707
-------- -------- --------
Total........................................ $ 77,061 $ 95,980 $162,647
======== ======== ========
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SFAS 109
The following is an analysis of accumulated deferred income taxes:
ACCUMULATED DEFERRED INCOME TAXES 1995 1994
---------- ----------
(THOUSANDS OF DOLLARS)
Assets:
Current (net)....................................................... $ 27,571 $ 25,311
Non-Current:
Unrecovered Investment Tax Credits............................... 129,713 136,402
Nuclear Decommissioning.......................................... 25,241 25,082
Hope Creek Cost Disallowance..................................... -- 10,127
Construction Period Interest and Taxes........................... 17,199 15,913
Vacation Pay..................................................... 6,681 6,822
Other............................................................ 5,057 6,863
---------- ----------
Total Non-Current........................................... $ 183,891 $ 201,209
---------- ----------
Total Assets................................................ $ 211,462 $ 226,520
========== ==========
Liabilities:
Non-Current:
Plant Related Items.............................................. $2,237,386 $2,157,206
Property Abandonments............................................ 21,469 26,971
Oil and Gas Property Write-Down.................................. 13,061 14,925
Deferred Electric Energy & Gas Costs............................. 56,283 59,884
Unamortized Debt Expense......................................... 36,945 37,599
Taxes Recoverable Through Future Rates (Net)..................... 262,625 270,684
Other............................................................ 91,725 112,479
---------- ----------
Total Non-Current........................................... $2,719,494 $2,679,748
---------- ----------
Total Liabilities........................................... $2,719,494 $2,679,748
========== ==========
Summary -- Accumulated Deferred Income Taxes
Net Current Assets.................................................. $ 27,571 $ 25,311
Net Deferred Liability.............................................. $2,535,603 $2,478,539
---------- ----------
Total....................................................... $2,508,032 $2,453,228
========== ==========
The balance of Federal income tax payable by PSE&G to Enterprise was $5.3 million and $15.6
million, as of December 31, 1995 and December 31, 1994, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONCLUDED)
NOTE 18. SELECTED QUARTERLY DATA (UNAUDITED)
The information shown below, in the opinion of PSE&G, includes all
adjustments, consisting only of normal recurring accruals, necessary to a fair
presentation of such amounts. Due to the seasonal nature of the utility
business, quarterly amounts vary significantly during the year.
CALENDAR MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31,
QUARTER ---------------------- ---------------------- ---------------------- ----------------------
ENDED 1995 1994 1995 1994 1995 1994 1995 1994
- ---------------------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
(THOUSANDS OF DOLLARS)
Operating Revenues.... $1,579,516 $1,690,999 $1,235,435 $1,182,880 $1,381,004 $1,284,175 $1,511,290 $1,360,187
Operating Income...... $ 298,432 $ 305,013 $ 204,606 $ 218,225 $ 280,525 $ 282,782 $ 211,939 $ 206,650
Net Income............ $ 206,896 $ 221,439 $ 111,300 $ 128,113 $ 184,878 $ 190,378 $ 113,890 $ 119,476
Earnings Available to
Public Service
Enterprise Group
Incorporated........ $ 198,214 $ 211,159 $ 102,620 $ 117,969 $ 176,196 $ 180,234 $ 105,698 $ 109,577
NOTE 19. ACCOUNTS PAYABLE TO ASSOCIATED COMPANIES -- NET
The balance at December 31, 1995 and 1994 consisted of the following:
1995 1994
------- -------
(THOUSANDS OF DOLLARS)
Public Service Enterprise Group Incorporated (A).......... $ 9,055 $17,678
Energy Development Corporation............................ (306) (336)
Other..................................................... (738) (665)
------- -------
Total.............................................. $ 8,011 $16,677
======= =======
(A) Principally Federal income taxes related to PSE&G's taxable income.
PART III
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Enterprise and PSE&G, none.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
DIRECTORS OF THE REGISTRANTS
Enterprise
The information required by Item 10 of Form 10-K with respect to
present directors who are nominees for election as directors at
Enterprise's Annual Meeting of Stockholders to be held on April 16,
1996, and directors whose terms will continue beyond the meeting, is
set forth under the heading "Election of Directors" in Enterprise's
definitive Proxy Statement for such Annual Meeting of Stockholders,
which definitive Proxy Statement is expected to be filed with the
Securities and Exchange Commission on or about March 1, 1996 and which
information set forth under said heading is incorporated herein by this
reference thereto.
PSE&G
There is shown as to each present director information as to the
period of service as a director of PSE&G, age as of April 16, 1996,
present committee memberships, business experience during the last five
years and other present directorships. For discussion of certain
litigation involving the directors of PSE&G, except Forrest J. Remick,
see Part I - Business, Item 3 - Legal Proceedings.
LAWRENCE R. CODEY has been a director since 1988. Age 51. Member
of Executive Committee. Has been President and Chief Operating Officer
of PSE&G since September 1991. Was Senior Vice President - Electric of
PSE&G from January 1989 to September 1991. Director of Enterprise.
Director of Sealed Air Corporation, The Trust Company of New Jersey,
United Water Resources Inc. and Blue Cross & Blue Shield of New Jersey.
E. JAMES FERLAND has been a director since 1986. Age 54. Chairman
of Executive Committee. Chairman of the Board, President and Chief
Executive Officer of Enterprise since July 1986, Chairman of the Board
and Chief Executive Officer of PSE&G since September 1991 and Chairman
of the Board and Chief Executive Officer of EDHI since June 1989.
President of PSE&G from July 1986 to September 1991. Director of
Enterprise and of EDHI and its principal subsidiaries. Director of
Foster Wheeler Corporation and The Hartford Steam Boiler Inspection and
Insurance Company.
RAYMOND V. GILMARTIN has been a director since 1993. Age 55.
Director of Enterprise. Has been Chairman of the Board, President and
Chief Executive Officer of Merck & Co., Inc., Whitehouse Station, New
Jersey (discovers, develops, produces and markets human and animal
health products) since November 1994. Was President and Chief
Executive Officer from June 1994 to November 1994. Was Chairman of the
Board, President and Chief Executive Officer of Becton Dickinson and
Company from November 1992 to June 1994 and President and Chief
Executive Officer from February 1989 to November 1992. Director of
Merck & Co., Inc. and Providian Corporation.
IRWIN LERNER has been a director since 1993. Age 65. Was
previously a director from 1981 to February 1988. Director of
Enterprise. Was Chairman, Board of Directors and Executive Committee
from January 1993 to September 1993 and President and Chief Executive
Officer from 1980 to December 1992 of Hoffmann-La Roche Inc., Nutley,
New Jersey (prescription pharmaceuticals, vitamins and fine chemicals,
and diagnostic products and services). Director of Humana Inc., Sequana
Therapeutics, Inc. and Medarex, Inc.
JAMES C. PITNEY has been a director since 1993. Age 69. Was
previously a director from 1979 to February 1988. Member of Executive
Committee. Director of Enterprise. Has been a partner in the law firm
of Pitney, Hardin, Kipp & Szuch, Morristown, New Jersey, since 1958.
Director of Tri-Continental Corporation, sixteen funds of the Seligman
family of funds and Seligman Quality, Inc.
FORREST J. REMICK has been a director since May 1995. Age 65.
Director of Enterprise. Has been an engineering consultant since July
1994. Was Commissioner, United States Nuclear Regulatory Commission,
from December 1989 to June 1994. Was Associate Vice President -
Research and Professor of Nuclear Engineering at Pennsylvania State
University, from 1985 to 1989.
Executive Officers of the Registrants
The following table sets forth certain information concerning the
executive officers of Enterprise and PSE&G, respectively.
AGE EFFECTIVE DATE
DECEMBER 31, FIRST ELECTED
NAME 1995 OFFICE TO PRESENT POSITION
- ------------------------------------ ---------------------------------- -------------------------
E. James Ferland........ 53 Chairman of the Board, President July 1986 to present
and Chief Executive Officer
(Enterprise)
Chairman of the Board and Chief July 1986 to present
Executive Officer (PSE&G)
President (PSE&G) June 1986 to September 1991
Chairman of the Board and Chief June 1989 to present
Executive Officer (EDHI)
Lawrence R. Codey....... 51 President and Chief Operating September 1991 to present
Officer (PSE&G)
Senior Vice President - Electric January 1989 to September 1991
(PSE&G)
Robert C. Murray........ 50 Vice President and Chief Financial January 1992 to present
Officer (Enterprise)
Senior Vice President and January 1992 to present
Chief Financial Officer
(PSE&G)
Managing Director of Morgan January 1987 to July 1991
Stanley & Co. Incorporated
Patricia A. Rado........ 53 Vice President and Controller April 1993 to present
(Enterprise)
Vice President and Controller April 1993 to present
(PSE&G)
Controller of Yankee Energy July 1989 to April 1993
Systems Inc.
Paul H. Way............. 58 President, Chief Operating February 1993 to present
Officer and Director (EDHI)
Senior Vice President (EDHI) June 1992 to February 1993
Senior Vice President - April 1988 to June 1992
Corporate Performance (PSE&G)
R. Edwin Selover........ 50 Vice President and General April 1988 to present
Counsel (Enterprise)
Senior Vice President and General January 1988 to present
Counsel (PSE&G)
Robert J. Dougherty, Jr. 44 President - Enterprise Ventures
and Services Corporation (PSE&G) February 1995 to present
Senior Vice President - Electric September 1991 to February 1995
(PSE&G)
Senior Vice President - Customer September 1989 to
Operations (PSE&G) September 1991
Leon R. Eliason......... 56 Chief Nuclear Officer and October 1994 to present
President - Nuclear Business
Unit (PSE&G)
President, Power Supply Business January 1993 to September 1994
Unit, Northern States Power
Vice President, Nuclear Genera- July 1990 to January 1993
tion, Northern States Power
Alfred C. Koeppe........ 49 Senior Vice President - External
Affairs (PSE&G) October 1995 to present
President and Chief Executive
Officer of Bell Atlantic -
New Jersey February 1993 to October 1995
Vice President - Public Affairs
of Bell Atlantic - New Jersey February 1991 to February 1993
ITEM 11. EXECUTIVE COMPENSATION
ENTERPRISE
The information required by Item 11 of Form 10-K is set forth under the
heading "Executive Compensation" in Enterprise's definitive Proxy Statement for
the Annual Meeting of Stockholders to be held April 16, 1996, which definitive
Proxy Statement is expected to be filed with the Securities and Exchange
Commission on or about March 1, 1996 and such information set forth under such
heading is incorporated herein by this reference thereto.
PSE&G
Information regarding the compensation of the Chief Executive Officer and
the four most highly compensated executive officers of PSE&G as of December 31,
1995 is set forth below. Amounts shown were paid or awarded for all services
rendered to Enterprise and its subsidiaries and affiliates including PSE&G.
SUMMARY COMPENSATION TABLE
LONG-TERM
COMPENSATION
---------------------
ANNUAL COMPENSATION AWARDS PAYOUTS
----------------------- --------- ---------
BONUS/ANNUAL LTIP ALL OTHER
SALARY INCENTIVE OPTIONS PAYOUTS COMPENSATION
NAME AND PRINCIPAL POSITION YEAR $ AWARD($)(/1/) (#)(/2/) ($)(/3/) ($)(/4/)
- --------------------------- ---- ------- ------------ ---------- ------- ------------
E. James Ferland.......
Chairman of the Board, 1995 682,377 (/5/) 5,800 246,288 8,681
President and CEO of 1994 652,492 251,383 5,400 127,140 5,628
Enterprise 1993 622,606 265,316 5,800 28,072 7,678
Lawrence R. Codey......
President and Chief 1995 418,392 (5) 2,800 118,746 5,756
Operating Officer of 1994 398,468 129,276 2,500 48,900 5,351
PSE&G 1993 378,545 109,585 2,800 9,570 6,981
Leon R. Eliason........
President - Nuclear 1995 323,755 165,000(/5/)(/6/) 5,500 26,388 3,242
Business Unit of 1994 74,713 0 600 0 0
PSE&G and 1993 0 0 0 0 0
Chief Nuclear Officer (/7/)
Robert J. Dougherty, Jr. .. 1995 322,759 (/5/) 2,500 70,368 4,269
Vice President of 1994 273,946 72,027 1,800 26,895 4,227
Enterprise and President of
Enterprise Ventures and
Services Corporation 1993 259,004 65,703 2,000 5,104 6,341
Robert C. Murray.......
Vice President and 1995 318,775 25,000(/5/)(/8/) 2,000 70,368 5,169
Chief Financial 1994 303,832 152,621(/8/) 1,800 26,895 4,944
Officer of Enterprise 1993 288,889 154,032(/8/) 2,000 3,190 7,264
(1) Amount awarded in given year was earned under Management Incentive Compensation Plan
(MICP) and determined in following year with respect to the given year based on
individual performance and financial and operating performance of Enterprise and PSE&G,
including comparison to other companies. Award is accounted for as market-priced phantom
stock with dividend reinvestment at 95% of market price, with payment made over three
years beginning in second year following grant.
(2) Granted under Long-Term Incentive Plan (LTIP) in tandem with equal number of
performance units and dividend equivalents which may provide cash payments, dependent
upon future financial performance of Enterprise in comparison to other companies and
dividend payments by Enterprise, to assist officers in exercising options granted. The
grant is made at the beginning of a three-year performance period and cash payment of the
value of such performance units and dividend equivalents is made following such period
in proportion to the options, if any, exercised at such time.
(3) Amount paid in proportion to options exercised, if any, based on value of previously
granted performance units and dividend equivalents, each as measured during three-year
period ending the year prior to the year in which payment is made.
(4) Includes employer contribution to Thrift and Tax-Deferred Savings Plan and value of
5% discount on phantom stock dividend reinvestment under MICP:
FERLAND CODEY ELIASON DOUGHERTY MURRAY
------------- ---------- ----------- --------- -----------
THRIFT MICP THRIFT MICP THRIFT MICP THRIFT MICP THRIFT MICP
------ ----- ------ ------ ------ ------ ------ ----- ------ ------
($) ($) ($) ($) ($) ($) ($) ($) ($)
1995.......... 3,752 2,383 4,502 1,254 1,795 0 3,754 515 4,502 667
1994.......... 3,751 1,877 4,197 1,154 0 0 3,752 475 4,504 440
1993.......... 5,900 1,778 5,896 1,085 0 0 5,907 434 7,078 186
In addition, for Mr. Ferland and Mr. Eliason, 1995 amounts include $2,546
and $1,447, respectively, representing interest on compensation deferred
under PSE&G's Deferred Compensation Plan in excess of 120% of the
applicable federal long-term rate as prescribed under Section 1274(d) of
the Internal Revenue Code. Under PSE&G's Deferred Compensation Plan,
interest is paid at prime rate plus 1/2%, adjusted quarterly.
(5) The 1995 MICP award amount has not yet been determined. The
target award is 40% of salary for Mr. Ferland, 30% for
Messrs. Codey, Eliason and Dougherty and 25% for Mr. Murray.
The target award is adjusted to reflect Enterprise's return
on capital, PSE&G's comparative electric and gas costs and
individual performance.
(6) Amount paid pursuant to Mr. Eliason's employment agreement.
(7) Mr. Eliason commenced employment September 26, 1994.
(8) 1995 amount paid pursuant to Mr. Murray's employment
agreement. 1994 and 1993 amounts include $50,000 and
$75,000, respectively, paid pursuant to Mr. Murray's
employment agreement.
OPTION GRANTS IN LAST FISCAL YEAR (1995)
INDIVIDUAL GRANTS
---------------------------------------------- POTENTIAL REALIZABLE
NUMBER VALUE AT ASSUMED ANNUAL
OF % OF TOTAL RATES OF STOCK PRICE
SECURITIES OPTIONS APPRECIATION FOR OPTION
UNDERLYING GRANTED TO EXERCISE OR TERM(2)
OPTIONS EMPLOYEES IN BASE PRICE EXPIRATION
NAME GRANTED(1) FISCAL YEAR ($/SH) DATE 0% ($) 5% ($) 10%($)
- ---------------------- --------------- ------------- -------------- ---------- --------- ------- --------
E. James Ferland.......... 5,800 16.6 26.625 1/04/05 0 97,117 246,114
Lawrence R. Codey......... 2,800 8.0 26.625 1/04/05 0 46,884 118,874
Leon R. Eliason........... 2,500 26.625 1/04/05 0 41,861 106,083
1,800 { 15.7 } 31.375 1/04/05 0 35,517 90,007
1,200 30.500 1/04/05 0 23,018 58,331
Robert J. Dougherty, Jr... 2,000 { 7.1 } 26.625 1/04/05 0 33,489 84,867
500 28.125 3/02/05 0 8,844 22,412
Robert C. Murray.......... 2,000 5.7 26.625 1/04/05 0 33,489 84,867
(1) Granted under LTIP in tandem with equal number of performance units and dividend equivalents which may provide
cash payments, dependent on future financial performance of Enterprise in comparison to other companies and
dividend payments by Enterprise, to assist individuals in exercising options, with exercisability commencing
January 1, 1998, except with respect to Mr. Eliason, for whom exercisabilty commences January 1, 1996, 1997 and
1998, respectively, for each of his three grants. Cash payment is made, based on the value, if any, of
performance units awarded and dividend equivalents accrued, if any, as measured during the three-year period
ending the year prior to the year in which payment, if any, is made, only if the specified performance level is
achieved, dividend equivalents have accrued and options are exercised.
(2) All options reported have a ten-year term, as noted. Amounts shown represent hypothetical future values at such
term based upon hypothetical price appreciation of Enterprise Common Stock and may not necessarily be realized.
Actual values which may be realized, if any, upon any exercise of such options, will be based on the market price
of Enterprise Common Stock at the time of any such exercise and thus are dependent upon future performance of
Enterprise Common Stock.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR (1995) AND FISCAL YEAR-END
OPTION VALUES (12/31/95)
VALUE OF UNEXERCISED
NUMBER OF UNEXERCISED IN-THE-MONEY OPTIONS
SHARES OPTIONS AT FY-END (#)(1) AT FY-END($)(3)
ACQUIRED VALUE ----------- -------------- ------------ ---------------
ON EXERCISE REALIZED EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
NAME (#)(1) ($)(2) (#) (#) ($) ($)
- ------------ ------------- --------- ------------- --------------- ------------ ---------------
E. James
Ferland....... 5,600 0 0 17,000 0 23,925
Lawrence R.
Codey......... 2,700 0 700 8,100 4,463 11,550
Leon R.
Eliason....... 600 72 0 5,500 0 10,150
Robert J
Dougherty..... 1,600 0 0 6,300 0 9,500
Robert C.
Murray........ 1,600 192 0 5,800 0 8,250
(1) Does not reflect any options granted and/or exercised after year-end (12/31/95). The net effect of any such grants and
exercises is reflected in the table appearing under Security Ownership of Directors and Management.
(2) Represents difference between exercise price and market price of Enterprise Common Stock on date of exercise.
(3) Represents difference between market price of Enterprise Common Stock and the respective exercise prices of the options
at fiscal year-end (12/31/95). Such amounts may not necessarily be realized. Actual values which may be realized, if any,
upon any exercise of such options will be based on the market price of Enterprise Common Stock at the time of any such
exercise and thus are dependent upon future performance of Enterprise Common Stock.
EMPLOYMENT CONTRACTS AND ARRANGEMENTS
Employment agreements were entered into with Messrs. Ferland, Eliason and Murray at the time of their employment. For
Mr. Ferland, the remaining applicable provisions of the agreement provide for additional credited service for pension purposes
in the amount of 22 years. . The principal remaining applicable terms of the agreement with Mr. Eliason provide for payment
of severance in the amount of one year's salary, if discharged without cause during his first five years of employment which
begin in September 1994, for lump sum cash payments of $100,000 in 1996, $65,000 in 1997 and $35,000 in 1998 to align Mr.
Eliason with MICP payments for other executive officers, and additional years of credited service for pension purposes for
allied work experience of 19 years after completion of three years of service, and up to 29 years after completion of ten years
of service. The principal remaining applicable terms of the agreement with Mr. Murray provide for payment of severance in the
amount of one year's salary, if discharged without cause during his first five years of employment, which began in January 1992,
and additional years of credited service for pension purposes for allied work experience of five years after completion of five
years of service, and up to fifteen years after completion of ten years of service
Compensation Committee Interlocks and Insider Participation
PSE&G does not have a compensation committee. Decisions regarding compensation of PSE&G's executive officers
are made by the Organization and Compensation Committee of Enterprise. Hence, during 1995 the PSE&G Board of Directors
did not have, and no officer, employee or former officer of PSE&G participated in any deliberations of such Board,
concerning executive officer compensation.
Compensation of Directors and Certain Business Relationships
A director who is not an officer of Enterprise or its subsidiaries and affiliates, including PSE&G, is paid an
annual retainer of $22,000 and a fee of $1,200 for attendance at any Board or committee meeting, inspection trip,
conference or other similar activity relating to Enterprise, PSE&G or EDHI. Each of the directors of PSE&G is also
a director of Enterprise. No additional retainer is paid for service as a director of PSE&G. Fifty percent of the
annual retainer is paid in Enterprise Common Stock.
Enterprise also maintains a Stock Plan for Outside Directors pursuant to which directors who are not employees
of Enterprise or its subsidiaries receive 300 shares of restricted stock for each year of service as a director. Such
shares held by each non-employee director are included in the table above under the heading Security Ownership of
Directors and Management. Prior to 1996, Enterprise had maintained a retirement plan for non-employee directors which
provided an annual benefit for life equal to the annual Board retainer in effect at the time the director's service
terminated if the director retired from the Board after 10 years of service. Participation of all current directors
under that plan was terminated December 31, 1995. As of January 1, 1996, current non-employee directors with ten
years or more of service received an award of shares of restricted stock equal to the present value of the retirement
benefit under this prior retirement plan, while those with less than ten years of service received an award of 300
shares per year of service. The number of shares awarded were as follows: Mr. Gilmartin: 900; Mr. Lerner: 3,768;
Mr. Pitney: 5,467; and Dr. Remick: 300. No current director remains eligible to receive a benefit under the prior
retirement plan.
The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are
subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following
his or her 70th birthday. This restriction would be deemed to have been satisfied if the director's service were
terminated if Enterprise were to merge with another corporation and not be the surviving corporation or if the
director were to die in office. Enterprise also has the ability to waive this restriction for good cause shown.
Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares
held subject to restrictions are paid directly to the director, and the director has the right to vote the shares.
Compensation Pursuant to Pension Plans
PENSION PLAN TABLE
AVERAGE LENGTH OF SERVICE
FINAL -----------------------------------------------
COMPENSATION 30 YEARS 35 YEARS 40 YEARS 45 YEARS
- ------------ -------- -------- -------- --------
$ 300,000 $180,000 $195,000 $210,000 $225,000
400,000 240,000 260,000 280,000 300,000
500,000 300,000 325,000 350,000 375,000
600,000 360,000 390,000 420,000 450,000
700,000 420,000 455,000 490,000 525,000
800,000 480,000 520,000 560,000 600,000
900,000 540,000 585,000 630,000 675,000
1,000,000 600,000 650,000 700,000 750,000
The above table illustrates annual retirement benefits expressed in terms of single life annuities based on
the average final compensation and service shown and retirement at age 65. A person's annual retirement benefit
is based upon a percentage that is equal to years of credited service plus 30, but not more than 75%, times average
final compensation at the earlier of retirement, attainment of age 65 or death. These amounts are reduced by Social
Security benefits and certain retirement benefits from other employers. Pensions in the form of joint and survivor
annuities are also available.
Average final compensation, for purposes of retirement benefits of executive officers, is generally equivalent
to the average of the aggregate of the salary and bonus amounts reported in the Summary Compensation Table above
under 'Annual Compensation' for the five years preceding retirement, not to exceed 120% of the average annual
salary for such five year period. Messrs. Ferland, Codey, Eliason, Dougherty and Murray will have accrued
approximately 48, 41, 44, 48 and 39 years of credited service, respectively, as of age 65.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Enterprise
The information required by Item 12 of Form 10-K with respect to directors and executive officers is set forth
under the heading 'Security Ownership of Directors and Management' in Enterprise's definitive Proxy Statement for the
Annual Meeting of Stockholders to be held April 16, 1996 which definitive Proxy Statement is expected to be filed with
the Securities and Exchange Commission on or about March 1, 1996 and such information set forth under such heading is
incorporated herein by this reference thereto.
PSE&G
All of PSE&G's 132,450,344 outstanding shares of Common Stock are owned beneficially and of record by PSE&G's
parent, Enterprise, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey.
The following table sets forth beneficial ownership of Enterprise Common Stock, including options, by the
directors and executive officers named below as of January 31, 1995. None of these amounts exceed 1% of the Enterprise
Common Stock outstanding at such date. No director or executive officer owns any PSE&G Preferred Stock of any class.
AMOUNT AND NATURE OF
NAME BENEFICIAL OWNERSHIP
- ------------------------------------- --------------------
Lawrence R. Codey................. 21,611(1)
Robert J. Dougherty, Jr........... 13,588(2)
Leon R. Eliason................... 8,600(3)
E. James Ferland.................. 63,479(4)
Raymond V. Gilmartin.............. 2,347
Irwin Lerner...................... 8,071
Robert C. Murray.................. 13,752(5)
James C. Pitney................... 8,864
Forrest J. Remick................. 676
All directors and executive
officers (12) as a group........ 157,582(6)
- ---------------
(1) Includes options to purchase 11,800 additional shares, 3,500 of which are currently exercisable.
(2) Includes the equivalent of 686 shares held under Thrift and Tax-Deferred Savings Plan. Include options to purchase
8,900 additional shares, 2,000 of which are currently exercisable.
(3) Includes options to purchase 8,000 additional shares, 1,200 of which are currently exercisable.
(4) Includes the equivalent of 9,432 shares held under Thrift and Tax-Deferred Savings Plan. Includes options to
purchase 23,500 additional shares, 5,800 of which are currently exercisable.
(5) Includes the equivalent of 752 shares held under Thrift and Tax-Deferred Savings Plan. Includes options to purchase
7,800 additional shares, 2,000 of which are currently exercisable.
(6) Includes the equivalent of 10,870 shares held under Thrift and Tax-Deferred Savings Plan. Includes options to
purchase 71,700 additional shares, of which 18,700 are currently exercisable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Enterprise
The information required by Item 13 of Form 10-K is set forth under the heading "Executive Compensation" in
Enterprise's definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 16, 1996, which definitive
Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 1, 1996. Such
information set forth under such heading is incorporated herein by this reference thereto.
PSE&G
None.
/TABLE
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) Financial Statements:
(1) Enterprise Consolidated Statements of Income for the
years ended December 31, 1995, 1994, and 1993, on page
97.
Enterprise Consolidated Balance Sheets for the years
ended December 31, 1995 and 1994, on pages 98 and 99.
Enterprise Consolidated Statements of Cash Flows for the
years ended December 31, 1995, 1994, and 1993 on page
100.
Enterprise Statements of Retained Earnings for the years
ended December 31, 1995, 1994, and 1993 on page 101.
Enterprise Notes to Consolidated Financial Statements on
pages 107 through 151.
(2) PSE&G Consolidated Statements of Income for the years
ended December 31, 1995, 1994, and 1993, on page 102.
PSE&G Consolidated Balance Sheets for the years ended
December 31, 1995 and 1994, on pages 103 and 104.
PSE&G Consolidated Statements of Cash Flows for the
years ended December 31, 1995, 1994, and 1993 on page
105.
PSE&G Statements of Retained Earnings for the years
ended December 31, 1995, 1994, and 1993 on page 106.
PSE&G Notes to Consolidated Financial Statements on
pages 152 through 155.
(b) The following documents are filed as a part of this report:
(1) Enterprise Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts
for each of the three years in the period ended
December 31, 1995 (page 166).
(2) PSE&G Financial Statement Schedules:
Schedule II -- Valuation and Qualifying Accounts
for each of the three years in the period ended
December 31, 1995 (page 167).
Schedules other than those listed above are
omitted for the reason that they are not required
or are not applicable, or the required
information is shown in the consolidated financial
statements or notes thereto.
(c) The following exhibits are filed herewith:
(1) Enterprise:
[S] [C]
10a(18) -- Directors Stock Plan
10a(19) -- Mid Career Hire Supplemental Retirement
Income Plan
10a(20) -- Retirement Income Reinstatement Plan
12 -- Computation of Ratios of Earnings to Fixed
Charges.
21 -- Subsidiaries of Registrant.
23 -- Independent Auditors' Consent.
27 -- Financial Data Schedule
(See Exhibit Index on pages 170 through 176).
(2) PSE&G:
[S] [C]
10a(18) -- Directors Stock Plan
10a(19) -- Mid Career Hire Supplemental Retirement
Income Plan
10a(20) -- Retirement Income Reinstatement Plan
12(a) -- Computation of Ratios of Earnings to Fixed
Charges.
12(b) -- Computation of Ratios of Earnings to Fixed
Charges Plus Preferred Stock Dividend
Requirements.
23 -- Independent Auditors' Consent.
27 -- Financial Data Schedule
(See Exhibit Index on page 170 and pages 177 through 182).
(d) The following reports on Form 8-K were filed by the
registrant(s) named below during the last quarter of
1995 and the 1996 period covered by this report under
Item 5:
REGISTRANT DATE OF REPORT ITEM REPORTED
- -------------- ------------------- --------------------------------
Enterprise and PSE&G January 19, 1996 Item 5. Other Events (Alternative Rate Plan
and change in credit agency rating)
Enterprise and PSE&G December 12, 1995 Item 5. (Nuclear Operations - Salem and
Energy Development Corporation Divestiture)
Enterprise and PSE&G October 17, 1995 Item 5. Other Events (Nuclear Operations -
Salem)
SCHEDULE II
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1995 -- DECEMBER 31, 1993
- -----------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- -----------------------------------------------------------------------------------------------------------------------
ADDITIONS
-------------------------------
CHARGED TO
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COST AND OTHER ACCOUNTS- DEDUCTIONS- END OF
DESCRIPTION PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD
- --------------------------------------------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS)
1995
Allowance for Doubtful Accounts........... $ 40,915 $ 32,555 $ -- $35,829(A) $ 37,641
============ ========== ============= =========== =========
Discount on Property Abandonments......... $ 11,423 $ -- $ -- $ 3,957(B) $ 7,466
============ ========== ============= =========== =========
Inventory Valuation Reserve............... $ 18,200 $ 1,900 $ -- $ -- $ 20,100
Valuation Allowances...................... $ 40,368 $ 4,241 $ 0,000 $ 15,079(c) $ 29,530
============ ========== ============= =========== =========
1994
Allowance for Doubtful Accounts........... $ 27,932 $ 50,140 $ -- $37,157(A) $ 40,915
============ ========== ============= =========== =========
Discount on Property Abandonments......... $ 16,263 $ -- $ -- $ 4,840(B) $ 11,423
============ ========== ============= =========== =========
Inventory Valuation Reserve............... $ 8,525 $ 9,675 $ -- $ -- $ 18,200
Valuation Allowances...................... $ 34,703 $ 6,827 $ 4,500 $ 5,662 $ 40,368
============ ========== ============= =========== =========
1993
Allowance for Doubtful Accounts........... $ 24,059 $ 31,625 $ -- $27,752(A) $ 27,932
============ ========== ============= =========== =========
Discount on Property Abandonments......... $ 21,951 $ -- $ -- $ 5,688(B) $ 16,263
============ ========== ============= =========== ========
Inventory Valuation Reserve............... $ -- $ 8,525 $ -- $ -- $ 8,525
Valuation Allowances...................... $ 21,509 $ 17,887 $ -- $ 4,693 $ 34,703
============ ========== ============= =========== ========
NOTES:
(A) Accounts Receivable/Investments written off.
(B) Amortization of discount to income.
(C) Assets Sold
SCHEDULE II
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1995 -- DECEMBER 31, 1993
- ------------------------------------------------------------------------------------------------------------------------
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
- ------------------------------------------------------------------------------------------------------------------------
ADDITIONS
----------------------------------
CHARGED TO
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COST AND OTHER ACCOUNTS- DEDUCTIONS- END OF
DESCRIPTION PERIOD EXPENSES DESCRIBE DESCRIBE PERIOD
- ------------------------------------------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS)
1995
Allowance for Doubtful Accounts........... $ 40,915 $ 32,555 $ -- $35,829(A) $ 37,641
============ ========== ============== =========== ==========
Discount on Property Abandonments......... $ 11,423 $ -- $ -- $ 3,957(B) $ 7,466
============ ========== ============== =========== ==========
Inventory Valuation Reserve............... $ 18,200 $ 1,900 $ -- $ -- $ 20,100
1994
Allowance for Doubtful Accounts........... $ 27,932 $ 50,140 $ -- $37,157(A) $ 40,915
============ ========== ============== =========== ==========
Discount on Property Abandonments......... $ 16,263 $ -- $ -- $ 4,840(B) $ 11,423
============ ========== ============== =========== ==========
Inventory Valuation Reserve............... $ 8,525 $ 9,675 $ -- $ -- $ 18,200
1993
Allowance for Doubtful Accounts........... $ 24,059 $ 31,625 $ -- $27,752(A) $ 27,932
============ ========== ============== =========== ==========
Discount on Property Abandonments......... $ 21,951 $ -- $ -- $ 5,688(B) $ 16,263
============ ========== ============== =========== ==========
Inventory Valuation Reserve............... $ -- $ 8,525 $ -- $ -- $ 8,525
NOTES:
(A) Accounts Receivable/Investments written off.
(B) Amortization of discount to income.
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.
PUBLIC SERVICE ENTERPRISE GROUP
INCORPORATED
By E. JAMES FERLAND
-------------------------------
E. James Ferland
Chairman of the Board, President
Date: February 22, 1996 and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of
the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
E. JAMES FERLAND
- -------------------------------- Chairman of the Board, February 22, 1996
E. James Ferland President and Chief
Executive Officer and
Director (Principal
Executive Officer)
ROBERT C. MURRAY
- -------------------------------- Vice President and Chief February 22, 1996
Robert C. Murray Financial Officer
(Principal Financial
Officer)
PATRICIA A. RADO
- -------------------------------- Vice President and February 22, 1996
Patricia A. Rado Controller (Principal
Accounting Officer)
LAWRENCE R. CODEY
- -------------------------------- Director February 22, 1996
Lawrence R. Codey
ERNEST H. DREW
- -------------------------------- Director February 22, 1996
Ernest H. Drew
T. J. DERMOT DUNPHY
- -------------------------------- Director February 22, 1996
T. J. Dermot Dunphy
RAYMOND V. GILMARTIN
- -------------------------------- Director February 22, 1996
Raymond V. Gilmartin
IRWIN LERNER
- -------------------------------- Director February 22, 1996
Irwin Lerner
MARILYN M. PFALTZ
- -------------------------------- Director February 22, 1996
Marilyn M. Pfaltz
JAMES C. PITNEY
- -------------------------------- Director February 22, 1996
James C. Pitney
FORREST J. REMICK
- -------------------------------- Director February 22, 1996
Forrest J. Remick
RICHARD J. SWIFT
- -------------------------------- Director February 22, 1996
Richard J. Swift
JOSH S. WESTON
- -------------------------------- Director February 22, 1996
Josh S. Weston
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.
PUBLIC SERVICE ELECTRIC AND GAS
COMPANY
By E. JAMES FERLAND
-------------------------------
E. James Ferland
Chairman of the Board and
Chief Executive Officer
Date: February 22, 1996
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
E. JAMES FERLAND
- -------------------------------- Chairman of the Board and February 22, 1996
E. James Ferland Chief Executive Officer
and Director (Principal
Executive Officer)
ROBERT C. MURRAY
- -------------------------------- Senior Vice President and February 22, 1996
Robert C. Murray Chief Financial Officer
(Principal Financial
Officer)
PATRICIA A. RADO
- -------------------------------- Vice President and February 22, 1996
Patricia A. Rado Controller (Principal
Accounting Officer)
LAWRENCE R. CODEY
- -------------------------------- Director February 22, 1996
Lawrence R. Codey
RAYMOND V. GILMARTIN
- -------------------------------- Director February 22, 1996
Raymond V. Gilmartin
IRWIN LERNER
- -------------------------------- Director February 22, 1996
Irwin Lerner
JAMES C. PITNEY
- -------------------------------- Director February 22, 1996
James C. Pitney
FORREST J. REMICK
- -------------------------------- Director February 22, 1996
Forrest J. Remick
EXHIBIT INDEX
Certain Exhibits previously filed with the Commission and the appropriate
securities exchanges are indicated as set forth below. Such Exhibits are not
being refiled, but are included because inclusion is desirable for convenient
reference.
(a) Filed by PSE&G with Form 8-A under the Securities Exchange Act
of 1934, on the respective dates indicated, File No. 1-973.
(b) Filed by PSE&G with Form 8-K under the Securities Exchange Act
of 1934, on the respective dates indicated, File No. 1-973.
(c) Filed by PSE&G with Form 10-K under the Securities Exchange Act
of 1934, on the respective dates indicated, File No. 1-973.
(d) Filed by PSE&G with Form 10-Q under the Securities Exchange Act
of 1934, on the respective dates indicated, File No. 1-973.
(e) Filed by Enterprise with Form 10-K under the Securities Exchange
Act of 1934, on the respective dates indicated, File No. 1-9120.
(f) Filed with registration statement of PSE&G under the Securities
Exchange Act of 1934, File No. 1-973, effective July 1, 1935, relating to
the registration of various issues of securities.
(g) Filed with registration statement of PSE&G under the Securities
Act of 1933, No. 2-4995, effective May 20, 1942, relating to the issuance
of $15,000,000 First and Refunding Mortgage Bonds, 3% Series due 1972.
(h) Filed with registration statement of PSE&G under the Securities
Act of 1933, No. 2-7568, effective July 1, 1948, relating to the proposed
issuance of 200,000 shares of Cumulative Preferred Stock.
(i) Filed with registration statement of PSE&G under the Securities
Act of 1933, No. 2-8381, effective April 18, 1950, relating to the
issuance of $26,000,000 First and Refunding Mortgage Bonds, 2 3/4%
Series due 1980.
(j) Filed with registration statement of PSE&G under the Securities
Act of 1933, No. 2-12906, effective December 4, 1956, relating to the
issuance of 1,000,000 shares of Common Stock.
(k) Filed with registration statement of PSE&G under the Securities
Act of 1933, No. 2-59675, effective September 1, 1977, relating to the
issuance of $60,000,000 First and Refunding Mortgage Bonds, 8 1/8%
Series I due 2007.
(l) Filed with registration statement of PSE&G under the Securities
Act of 1933, No. 2-60925, effective March 30, 1978, relating to the
issuance of 750,000 shares of Common Stock through an Employee Stock
Purchase Plan.
(m) Filed with registration statement of PSE&G under the Securities
Act of 1933, No. 2-65521, effective October 10, 1979, relating to the
issuance of 3,000,000 shares of Common Stock.
(n) Filed with registration statement of PSE&G under the Securities
Act of 1933, No. 2-74018, filed on June 16, 1982, relating to the Thrift
Plan of PSE&G.
(o) Filed with registration statement of Public Service Enterprise
Group Incorporated under the Securities Act of 1933, No. 33-2935 filed
January 28, 1986, relating to PSE&G's plan to form a holding company as
part of a corporate restructuring.
(p) Filed with registration statement of PSE&G under the Securities
Act of 1933, No. 33-13209 filed April 9, 1987, relating to the
registration of $575,000,000 First and Refunding Mortgage Bonds
pursuant to Rule 415.
ENTERPRISE
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
3a (o) 3a (o) 3a Certificate of Incorporation Public Service
Enterprise Group Incorporated
3b (e) 3b (e) 3b Copy of By-Laws of Public Service Enterprise
4/11/88 Group Incorporated, as in effect May 1, 1987
3c (e) 3c (e) 3c Certificate of Amendment of Certificate of
4/11/88 Incorporation of Public Service Enterprise Group
Incorporated, effective April 23, 1987
4a(1) (f) B-1 (c) 4b(1) Indenture between PSE&G and Fidelity Union Trust
2/18/81 Company, (now First Fidelity Bank, National
Association), as Trustee, dated August 1, 1924,
securing First and Refunding Mortgage Bonds
Indentures between PSE&G and First Fidelity
Bank, National Association, as Trustee,
supplemental to Exhibit 4a(1), dated as follows:
4a(2) (i) 7(1a) (c) 4b(2) April 1, 1927
2/18/81
4a(3) (k) 2b(3) (c) 4b(3) June 1, 1937
2/18/81
4a(4) (k) 2b(4) (c) 4b(4) July 1, 1937
2/18/81
4a(5) (k) 2b(5) (c) 4b(5) December 19, 1939
2/18/81
4a(6) (g) B-10 (c) 4b(6) March 1, 1942
2/18/81
4a(7) (k) 2b(7) (c) 4b(7) June 1, 1949
2/18/81
4a(8) (k) 2b(8) (c) 4b(8) May 1, 1950
2/18/81
4a(9) (k) 2b(9) (c) 4b(9) October 1, 1953
2/18/81
4a(10) (k) 2b(10) (c) 4b(10) May 1, 1954
2/18/81
4a(11) (j) 4b(16) (c) 4b(11) November 1, 1956
2/18/81
4a(12) (k) 2b(12) (c) 4b(12) September 1, 1957
2/18/81
4a(13) (k) 2b(13) (c) 4b(13) August 1, 1958
2/18/81
4a(14) (k) 2b(14) (c) 4b(14) June 1, 1959
2/18/81
4a(15) (k) 2b(15) (c) 4b(15) September 1, 1960
2/18/81
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
4a(16) (k) 2b(16) (c) 4b(16) August 1, 1962
2/18/81
4a(17) (k) 2b(17) (c) 4b(17) June 1, 1963
2/18/81
4a(18) (k) 2b(18) (c) 4b(18) September 1, 1964
2/18/81
4a(19) (k) 2b(19) (c) 4b(19) September 1, 1965
2/18/81
4a(20) (k) 2b(20) (c) 4b(20) June 1, 1967
2/18/81
4a(21) (k) 2b(21) (c) 4b(21) June 1, 1968
2/18/81
4a(22) (k) 2b(22) (c) 4b(22) April 1, 1969
2/18/91
4a(23) (k) 2b(23) (c) 4b(23) March 1, 1970
2/18/81
4a(24) (k) 2b(24) (c) 4b(24) May 15, 1971
2/18/81
4a(25) (k) 2b(25) (c) 4b(25) November 15, 1971
2/18/81
4a(26) (k) 2b(26) (c) 4b(26) April 1, 1972
2/18/81
4a(27) (a) 2 (c) 4b(27) March 1, 1974
3/29/74 2/18/81
4a(28) (a) 2 (c) 4b(28) October 1, 1974
10/11/74 2/18/81
4a(29) (a) 2 (c) 4b(29) April 1, 1976
4/6/76 2/18/81
4a(30) (a) 2 (c) 4b(30) September 1, 1976
9/16/76 2/18/81
4a(31) (k) 2b(31) (c) 4b(31) October 1, 1976
2/18/81
4a(32) (a) 2 (c) 4b(32) June 1, 1977
6/29/77 2/18/81
4a(33) (l) 2b(33) (c) 4b(33) September 1, 1977
2/18/81
4a(34) (a) 2 (c) 4b(34) November 1, 1978
11/21/78 2/18/81
4a(35) (a) 2 (c) 4b(35) July 1, 1979
7/25/79 2/18/81
4a(36) (m) 2d(36) (c) 4b(36) September 1, 1979 (No. 1)
2/18/81
4a(37) (m) 2d(37) (c) 4b(37) September 1, 1979 (No. 2)
2/18/81
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
4a(38) (a) 2 (c) 4b(38) November 1, 1979
12/3/79 2/18/81
4a(39) (a) 2 (c) 4b(39) June 1, 1980
6/10/80 2/18/81
4a(40) (a) 2 (a) 2 August 1, 1981
8/19/81 8/19/81
4a(41) (b) 4e (b) 4e April 1, 1982
4/29/82 5/5/82
4a(42) (a) 2 (a) 2 September 1, 1982
9/17/82 9/20/82
4a(43) (a) 2 (a) 2 December 1, 1982
12/21/82 12/21/82
4a(44) (d) 4(ii) (d) 4(ii) June 1, 1983
7/26/83 7/27/83
4a(45) (a) 4 (a) 4 August 1, 1983
8/19/83 8/19/83
4a(46) (d) 4(ii) (d) 4(ii) July 1, 1984
8/14/84 8/17/84
4a(47) (d) 4(ii) (d) 4(ii) September 1, 1984
11/2/84 11/9/84
4a(48) (b) 4(ii) (b) 4(ii) November 1, 1984 (No. 1)
1/4/85 1/9/85
4a(49) (b) 4(ii) (b) 4(ii) November 1, 1984 (No. 2)
1/4/85 1/9/85
4a(50) (a) 2 (a) 2 July 1, 1985
8/2/85 8/2/85
4a(51) (c) 4a(51) (c) 4a(51) January 1, 1986
2/11/86 2/11/86
4a(52) (a) 2 (a) 2 March 1, 1986
3/28/86 3/28/86
4a(53) (a) 2(a) (a) 2(a) April 1, 1986 (No. 1)
5/1/86 5/1/86
4a(54) (a) 2(b) (a) 2(b) April 1, 1986 (No. 2)
5/1/86 5/1/86
4a(55) (p) 4a(55) (p) 4a(55) March 1, 1987
4/9/87 4/9/87
4a(56) (a) 4 (a) 4 July 1, 1987 (No. 1)
8/17/87 8/17/87
4a(57) (d) 4 (d) 4 July 1, 1987 (No. 2)
11/13/87 11/20/87
4a(58) (a) 4 (a) 4 May 1, 1988
5/17/88 5/18/88
4a(59) (a) 4 (a) 4 September 1, 1988
9/27/88 9/28/88
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
4a(60) (a) 4 (a) 4 July 1, 1989
7/25/89 7/26/89
4a(61) (a) 4 (a) 4 July 1, 1990 (No. 1)
7/25/90 7/26/90
4a(62) (a) 4 (a) 4 July 1, 1990 (No. 2)
7/25/90 7/26/90
4a(63) (a) 4 (a) 4 June 1, 1991 (No. 1)
7/1/91 7/2/91
4a(64) (a) 4 (a) 4 June 1, 1991 (No. 2)
7/1/91 7/2/91
4a(65) (a) 4 (a) 4 November 1, 1991 (No. 1)
12/2/91 12/3/91
4a(66) (a) 4 (a) 4 November 1, 1991 (No. 2)
12/2/91 12/3/91
4a(67) (a) 4 (a) 4 November 1, 1991 (No. 3)
12/2/91 12/3/91
4a(68) (a) 4 (a) 4 February 1, 1992 (No. 1)
2/27/92 2/28/92
4a(69) (a) 4 (a) 4 February 1, 1992 (No. 2)
2/27/92 2/28/92
4a(70) (a) 4 (a) 4 June 1, 1992 (No. 1)
6/17/92 6/11/92
4a(71) (a) 4 (a) 4 June 1, 1992 (No. 2)
6/17/92 6/11/92
4a(72) (a) 4 (a) 4 June 1, 1992 (No. 3)
6/17/92 6/11/92
4a(73) (a) 4 (a) 4 January 1, 1993 (No.1)
2/2/93 2/2/93
4a(74) (a) 4 (a) 4 January 1, 1993 (No. 2)
2/2/93 2/2/93
4a(75) (a) 4 (a) 4 March 1, 1993
3/17/93 3/18/93
4a(76) (b) 4 (a) 4 May 1, 1993
5/27/93 5/28/93
4a(77) (a) 4 (a) 4 May 1, 1993 (No. 2)
5/25/93 5/25/93
4a(78) (a) 4 (a) 4 May 1, 1993 (No. 3)
5/25/93 5/25/93
4a(79) (b) 4 (b) 4 July 1, 1993
12/1/93 12/1/93
4a(80) (a) 4 (a) 4 August 1, 1993
8/3/93 8/3/93
4a(81) (b) 4 (b) 4 September 1, 1993
12/1/93 12/1/93
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
4a(82) (b) 4 (b) 4 September 1, 1993 (No. 2)
12/1/93 12/1/93
4a(83) (b) 4 (b) 4 November 1, 1993
12/1/93 12/1/93
4a(84) (a) 4 (a) 4 February 1, 1994
2/3/94 2/14/94
4a(85) (a) 4 (a) 4 March 1, 1994 (No. 1)
3/15/94 3/16/94
4a(86) (a) 4 (a) 4 March 1, 1994 (No. 2)
3/15/94 3/16/94
4a(87) (d) 4 (d) 4 May 1, 1994
11/8/94 12/2/94
4a(88) (d) 4 (d) 4 June 1, 1994
11/8/94 12/2/94
4a(89) (d) 4 (d) 4 August 1, 1994
11/8/94 12/2/94
4a(90) (d) 4 (d) 4 October 1, 1994 (No. 1)
11/8/94 12/2/94
4a(91) (d) 4 (d) 4 October 1, 1994 (No. 2)
11/8/94 12/2/94
4a(92) (a) 4 (a) 4 January 1, 1996 (No.1)
1/26/96 1/26/96
4a(93) (a) 4 (a) 4 January 1, 1996 (No.2)
1/26/96 1/26/96
4b (h) 7(12) (c) 4c(1) Indenture between PSE&G and Federal Trust
2/18/81 Company, as Trustee (Midlantic National Bank,
Successor Trustee) dated July 1, 1948, providing
for 6% Debenture Bonds due 1998
4c (l) 2c(8) (c) 4c(8) Indenture between PSE&G and The Chase Manhattan
2/18/81 Bank (National Association), as Trustee, dated
August 15, 1971, providing for 7 3/4% Debenture
Bonds due 1996
4d (b) 4 (b) 4 Indenture of Trust between PSE&G and The Chase
12/1/93 12/1/93 Manhattan Bank (National Association), as
Trustee, providing for Secured Medium-Term Notes
dated July 1, 1993
4e(1) (c) (c) Indenture between PSE&G and First Fidelity Bank,
2/23/95 2/23/95 National Association, as Trustee, dated
November 1, 1994, providing for Deferrable
Interest Subordinated Debentures in Series
4e(2) (a) (a) Supplemental Indenture between PSE&G and First
9/11/95 9/11/95 Fidelity Bank, National Association, as Trustee,
dated September 11, 1995 providing for Deferrable
Interest Subordinated Debentures, Series B
9 Inapplicable
10a(1) (c) 10c(1) (c) 10c(1) Directors' Deferred Compensation Plan
3/17/82 3/19/82
10a(2) (c) 10c(2) (c) 10c(2) Officers' Deferred Compensation Plan
3/17/82 3/19/82
10a(3) (c) 10c(3) (c) 10c(3) Supplemental Death Benefits Plan for officers
3/17/82 3/19/82
10a(4) (c) 10c(4) (c) 10c(4) Description of additional retirement benefits
3/17/82 3/19/82 for certain officers
10a(5)(i) (c) 10b(5) (c) 10b(5) Limited Supplemental Death Benefits and
3/31/83 4/8/83 Retirement Plan
10a(5)(ii) (c) 10a(5)(ii) (c) 10a(5)(ii) Limited Supplemental Benefits Plan for Certain
2/25/94 3/1/94 Employees
10a(6)(i) (c) 10a(6) (c) 10a(6) Description of additional retirement benefits
3/10/87 4/16/87 for certain officers
10a(6)(ii) (c) 10a(6)(1) (c) 10a(6)(1) Description of additional retirement benefits
3/30/90 3/30/90 for certain officers.
10a(6)(iii) (c) 10a(6)(2) (c) 10a(6)(2) Description of additional retirement benefits
3/30/92 4/27/92 for a certain officer.
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
10a(7) (o) 10g (o) 10g Management Incentive Compensation Plan
10a(8) (c) 10a(8) (c) 10a(8) Long-Term Incentive Plan
3/30/89 4/18/89
10a(9) (c) 10a(9) (c) 10a(9) Public Service Enterprise Group Incorporated
3/30/89 4/18/89 Pension Plan for Outside Directors
10a(10) (c) 10a(11) (c) 10a(11) Letter Agreement with E. James Ferland dated
2/10/93 2/11/93 April 16, 1986
10a(11) (c) 10a(12) (c) 10a(12) Letter Agreement with Paul H. Way dated March
2/10/93 2/11/93 28, 1988
10a(12) (c) 10a(13) (c) 10a(13) Letter Agreement with Thomas M. Crimmins, Jr.
2/10/93 2/11/93 dated April 5, 1989
10a(13) (c) 10a(15) (c) 10a(15) Letter Agreement with Robert C. Murray dated
2/10/93 2/11/93 December 17, 1991
10a(14) (c) 10a(14) (c) 10a(14) Letter agreement with Patricia A. Rado dated
2/26/94 3/9/94 March 24, 1993
10a(15) (c) 10a(15) (c) 10a(15) Letter Agreement, as amended, with Leon R.
2/23/95 2/23/95 Eliason dated September 14, 1994
10a(16) (d) 10a(15) (d) 10a(15) Letter Agreement with Louis F. Storz dated
8/14/95 8/14/95 July 7, 1995
10a(17) (d) 10a(16) (d) 10a(16) Letter Agreement with Elbert C. Simpson dated
8/14/95 8/14/95 May 31, 1995
10a(18) (d) 10a(17) (d) 10a(17) Letter Agreement with Alfred C. Koeppe dated
11/14/95 11/14/95 August 23, 1995
10a(19) Director Stock Plan
10a(20) Mid Career Hire Supplemental Retirement Plan
10a(21) Retirement Income Reinstatement Plan
11 Inapplicable
12 Computation of Ratios of Earnings to Fixed
Charges
13 Inapplicable
16 Inapplicable
18 Inapplicable
21 Subsidiaries of the Registrant
22 Inapplicable
23 Independent Auditors' Consent
24 Inapplicable
27 Financial Data Schedule
28 Inapplicable
99 Inapplicable
PSE&G
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
3a(1) (b) 3a (b) 3a Restated Certificate of Incorporation of PSE&G,
8/28/86 8/29/86 effective May 1, 1986
3a(2) (c) 3a(2) (c) 3a(2) Certificate of Amendment of Certificate of
4/10/87 Restated Certificate of Incorporation of PSE&G
filed February 18, 1987 with the State of New
Jersey adopting limitations of liability
provisions in accordance with an amendment to
New Jersey Business Corporation Act
3a(3) (a) 3(a)3 (a) 3(a)3 Certificate of Amendment of Restated Certificate
2/3/94 2/14/94 of Incorporation of PSE&G filed June 17, 1992
with the State of New Jersey, establishing the
7.44% Cumulative Preferred Stock ($100 Par) as a
series of the Preferred Stock
3a(4) (a) 3(a)4 (a) 3(a)4 Certificate of Amendment of Restated Certificate
2/3/94 2/14/94 of Incorporation of PSE&G filed March 11, 1993
with the State of New Jersey, establishing the
5.97% Cumulative Preferred Stock ($100 Par) as a
series of Preferred Stock
3a(5) (a) 3(a)5 (a) 3(a)5 Certificate of Amendment of Restated Certificate
2/3/94 2/14/94 of Incorporation of PSE&G filed January 27, 1994
with the State of New Jersey, establishing the
6.92% Cumulative Preferred Stock ($100 Par) and
the 6.75% Cumulative Preferred Stock -- $25 Par as
series of Preferred Stock
3b Copy of By-Laws of PSE&G, as in effect
September 1, 1994
4a(1) (f) B-1 (c) 4b(1) Indenture between PSE&G and Fidelity Union Trust
2/18/81 Company, (now First Fidelity Bank, National
Association), as Trustee, dated August 1, 1924,
securing First and Refunding Mortgage Bonds
Indentures between PSE&G and First Fidelity
Bank, National Association, as Trustee,
supplemental to Exhibit 4a(1), dated as follows:
4a(2) (i) 7(1a) (c) 4b(2) April 1, 1927
2/18/81
4a(3) (k) 2b(3) (c) 4b(3) June 1, 1937
2/18/81
4a(4) (k) 2b(4) (c) 4b(4) July 1, 1937
2/18/81
4a(5) (k) 2b(5) (c) 4b(5) December 19, 1939
2/18/81
4a(6) (g) B-10 (c) 4b(6) March 1, 1942
2/18/81
4a(7) (k) 2b(7) (c) 4b(7) June 1, 1949
2/18/81
4a(8) (k) 2b(8) (c) 4b(8) May 1, 1950
2/18/81
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
4a(9) (k) 2b(9) (c) 4b(9) October 1, 1953
2/18/81
4a(10) (k) 2b(10) (c) 4b(10) May 1, 1954
2/18/81
4a(11) (j) 4b(16) (c) 4b(11) November 1, 1956
2/18/81
4a(12) (k) 2b(12) (c) 4b(12) September 1, 1957
2/18/81
4a(13) (k) 2b(13) (c) 4b(13) August 1, 1958
2/18/81
4a(14) (k) 2b(14) (c) 4b(14) June 1, 1959
2/18/81
4a(15) (k) 2b(15) (c) 4b(15) September 1, 1960
2/18/81
4a(16) (k) 2b(16) (c) 4b(16) August 1, 1962
2/18/81
4a(17) (k) 2b(17) (c) 4b(17) June 1, 1963
2/18/81
4a(18) (k) 2b(18) (c) 4b(18) September 1, 1964
2/18/81
4a(19) (k) 2b(19) (c) 4b(19) September 1, 1965
2/18/81
4a(20) (k) 2b(20) (c) 4b(20) June 1, 1967
2/18/81
4a(21) (k) 2b(21) (c) 4b(21) June 1, 1968
2/18/81
4a(22) (k) 2b(22) (c) 4b(22) April 1, 1969
2/18/81
4a(23) (k) 2b(23) (c) 4b(23) March 1, 1970
2/18/81
4a(24) (k) 2b(24) (c) 4b(24) May 15, 1971
2/18/81
4a(25) (k) 2b(25) (c) 4b(25) November 15, 1971
2/18/81
4a(26) (k) 2b(26) (c) 4b(26) April 1, 1972
2/18/81
4a(27) (a) 2 (c) 4b(27) March 1, 1974
3/29/74 2/18/81
4a(28) (a) 2 (c) 4b(28) October 1, 1974
10/11/74 2/18/81
4a(29) (a) 2 (c) 4b(29) April 1, 1976
4/6/76 2/18/81
4a(30) (a) 2 (c) 4b(30) September 1, 1976
9/16/76 2/18/81
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
4a(31) (k) 2b(31) (c) 4b(31) October 1, 1976
2/18/81
4a(32) (a) 2 (c) 4b(32) June 1, 1977
6/29/77 2/18/81
4a(33) (l) 2b(33) (c) 4b(33) September 1, 1977
2/18/81
4a(34) (a) 2 (c) 4b(34) November 1, 1978
11/21/78 2/18/81
4a(35) (a) 2 (c) 4b(35) July 1, 1979
7/25/79 2/18/81
4a(36) (m) 2d(36) (c) 4b(36) September 1, 1979 (No. 1)
2/18/81
4a(37) (m) 2d(37) (c) 4b(37) September 1, 1979 (No. 2)
2/18/81
4a(38) (a) 2 (c) 4b(38) November 1, 1979
12/3/79 2/18/81
4a(39) (a) 2 (c) 4b(39) June 1, 1980
6/10/80 2/18/81
4a(40) (a) 2 (a) 2 August 1, 1981
8/19/81 8/19/81
4a(41) (b) 4e (b) 4e April 1, 1982
4/29/82 5/5/82
4a(42) (a) 2 (a) 2 September 1, 1982
9/17/82 9/20/82
4a(43) (a) 2 (a) 2 December 1, 1982
12/21/82 12/21/82
4a(44) (d) 4(ii) (d) 4(ii) June 1, 1983
7/26/83 7/27/83
4a(45) (a) 4 (a) 4 August 1, 1983
8/19/83 8/19/83
4a(46) (d) 4(ii) (d) 4(ii) July 1, 1984
8/14/84 8/17/84
4a(47) (d) 4(ii) (d) 4(ii) September 1, 1984
11/2/84 11/9/84
4a(48) (b) 4(ii) (b) 4(ii) November 1, 1984 (No. 1)
1/4/85 1/9/85
4a(49) (b) 4(ii) (b) 4(ii) November 1, 1984 (No. 2)
1/4/85 1/9/85
4a(50) (a) 2 (a) 2 July 1, 1985
8/2/85 8/2/85
4a(51) (c) 4a(51) (c) 4a(51) January 1, 1986
2/11/86 2/11/86
4a(52) (a) 2 (a) 2 March 1, 1986
3/28/86 3/28/86
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
4a(53) (a) 2(a) (a) 2(a) April 1, 1986 (No. 1)
5/1/86 5/1/86
4a(54) (a) 2(b) (a) 2(b) April 1, 1986 (No. 2)
5/1/86 5/1/86
4a(55) (p) 4a(55) (p) 4a(55) March 1, 1987
4/9/87 4/9/87
4a(56) (a) 4 (a) 4 July 1, 1987 (No. 1)
8/17/87 8/17/87
4a(57) (d) 4 (d) 4 July 1, 1987 (No. 2)
11/13/87 11/20/87
4a(58) (a) 4 (a) 4 May 1, 1988
5/17/88 5/18/88
4a(59) (a) 4 (a) 4 September 1, 1988
9/27/88 9/28/88
4a(60) (a) 4 (a) 4 July 1, 1989
7/25/89 7/26/89
4a(61) (a) 4 (a) 4 July 1, 1990 (No. 1)
7/25/90 7/26/90
4a(62) (a) 4 (a) 4 July 1, 1990 (No. 2)
7/25/90 7/26/90
4a(63) (a) 4 (a) 4 June 1, 1991 (No. 1)
7/1/91 7/2/91
4a(64) (a) 4 (a) 4 June 1, 1991 (No. 2)
7/1/91 7/2/91
4a(65) (a) 4 (a) 4 November 1, 1991 (No. 1)
12/2/91 12/3/91
4a(66) (a) 4 (a) 4 November 1, 1991 (No. 2)
12/2/91 12/3/91
4a(67) (a) 4 (a) 4 November 1, 1991 (No. 3)
12/2/91 12/3/91
4a(68) (a) 4 (a) 4 February 1, 1992 (No. 1)
2/27/92 2/28/92
4a(69) (a) 4 (a) 4 February 1, 1992 (No. 2)
2/27/92 2/28/92
4a(70) (a) 4 (a) 4 June 1, 1992 (No. 1)
6/17/92 6/11/92
4a(71) (a) 4 (a) 4 June 1, 1992 (No. 2)
6/17/92 6/11/92
4a(72) (a) 4 (a) 4 June 1, 1992 (No. 3)
6/17/92 6/11/92
4a(73) (a) 4 (a) 4 January 1, 1993 (No.1)
2/2/93 2/2/93
4a(74) (a) 4 (a) 4 January 1, 1993 (No. 2)
2/2/93 2/2/93
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
4a(75) (a) 4 (a) 4 March 1, 1993
3/17/93 3/18/93
4a(76) (b) 4 (a) 4 May 1, 1993
5/27/93 5/28/93
4a(77) (a) 4 (a) 4 May 1, 1993 (No. 2)
5/25/93 5/25/93
4a(78) (a) 4 (a) 4 May 1, 1993 (No. 3)
5/25/93 5/25/93
4a(79) (b) 4 (b) 4 July 1, 1993
12/1/93 12/1/93
4a(80) (a) 4 (a) 4 August 1, 1993
8/3/93 8/3/93
4a(81) (b) 4 (b) 4 September 1, 1993
12/1/93 12/1/93
4a(82) (a) 4 (a) 4 September 1, 1993 (No. 2)
12/1/93 12/1/93
4a(83) (b) 4 (b) 4 November 1, 1993
12/1/93 12/1/93
4a(84) (a) 4 (a) 4 February 1, 1994
2/3/94 2/14/94
4a(85) (a) 4 (a) 4 March 1, 1994 (No. 1)
3/15/94 3/16/94
4a(86) (a) 4 (a) 4 March 1, 1994 (No. 2)
3/15/94 3/16/94
4a(87) (d) 4 (d) 4 May 1, 1994
11/8/94 12/2/94
4a(88) (d) 4 (d) 4 June 1, 1994
11/8/94 12/2/94
4a(89) (d) 4 (d) 4 August 1, 1994
11/8/94 12/2/94
4a(90) (d) 4 (d) 4 October 1, 1994 (No. 1)
11/8/94 12/2/94
4a(91) (d) 4 (d) 4 October 1, 1994 (No. 2)
11/8/94 12/2/94
4a(92) (a) 4 (a) 4 January 1, 1996 (No.1)
1/26/96 1/26/96
4a(93) (a) 4 (a) 4 January 1, 1996 (No.2)
1/26/96 1/26/96
4b(1) (h) 7(12) (c) 4c(1) Indenture between PSE&G and Federal Trust
2/18/81 Company, as Trustee, (Midlantic National Bank,
Successor Trustee) dated July 1, 1948, providing
for 6% Debenture Bonds due 1998
4b(2) (l) 2c(8) (c) 4c(8) Indenture between PSE&G and the Chase Manhattan
2/18/81 Bank (National Association), as Trustee, dated
August 15, 1971, providing for 7 3/4% Debenture
Bonds due 1996
4b(3) (b) 4 (b) 4 Indenture of Trust between the Company and The
12/1/93 12/1/93 Chase Manhattan Bank (National Association), as
Trustee, providing for Secured Medium-Term Notes
dated July 1, 1993
4b(4) (b) (c) Indenture between PSE&G and First Fidelity Bank,
2/2395 2/23/95 National Association, as Trustee, dated
November 1, 1994, providing for Deferrable
Interest Subordinated Debentures in Series
4b(5) (a) 4b(5) (a) 4b(5) Supplemental Indenture between PSE&G and First
Fidelity Bank, National Association, as Trustee,
dated September 11, 1995 providing for Deferrable
Interest Subordinated Debentures in Series B
9 Inapplicable
10a(1) (c) 10c(1) (c) 10c(1) Directors' Deferred Compensation Plan
3/17/82 3/19/82
10a(2) (c) 10c(2) (c) 10c(2) Officers' Deferred Compensation Plan
3/17/82 3/19/82
Supplemental Benefits Plan for Certain
2/25/94 3/1/94 Employees
EXHIBIT NUMBER
- --------------------------------------------
PREVIOUS FILING
THIS --------------------------------
FILING COMMISSION EXCHANGES
- --------- -------------- --------------
10a(3) (c) 10c(3) (c) 10c(3) Supplemental Death Benefits Plan for officers
3/17/82 3/19/82
10a(4) (c) 10c(4) (c) 10c(4) Description of additional retirement for certain
3/17/82 3/19/82 officers
10a(5)(i) (c) 10b(5) (c) 10b(5) Limited Supplemental Death Benefits and
3/31/83 4/8/83 Retirement Plan
10a(5)(ii) (c) 10a(5)(ii) (c) 10a(5)(ii) Limited S-----
10a(6)(i) (c) 10a(6) (c) 10a(6) Description of additional retirement benefits
3/10/87 4/16/87 for certain officers
10a(6)(ii) (c) 10a(6)(1) (c) 10a(6)(1) Description of additional retirement benefit for
3/30/90 3/30/90 certain officers.
10a(6)(iii) (c) 10a(6)(2) (c) 10a(6)(2) Description of additional retirement benefit for
3/30/92 4/27/92 a certain officer.
10a(7) (o) 10g (o) 10g Management Incentive Compensation Plan
10a(8) (c) 10a(8) (c) 10a(8) Long-Term Incentive Plan
3/30/89 4/18/89
10a(9) (c) 10a(9) (c) 10a(9) Public Service Enterprise Group Incorporated
3/30/89 4/18/89 Pension Plan for Outside Directors
10a(10) (c) 10a(9) (c) 10a(9) Letter Agreement with E. James Ferland dated
2/10/93 2/11/93 April 16, 1986
10a(11) (c) 10a(10) (c) 10a(10) Letter Agreement with Thomas M. Crimmins, Jr.
2/10/93 2/11/93 dated April 5, 1989
10a(12) (c) 10a(12) (c) 10a(12) Letter Agreement with Robert C. Murray dated
2/10/93 2/11/93 December 17, 1991
10a(13) (c) 10a(13) (c) 10a(13) Letter agreement with Patricia A. Rado dated
2/26/94 3/9/94 March 24, 1993.
10a(14) (c) 10a(14) (c) 10a(14) Letter Agreement, as amended, with Leon R.
2/23/95 2/23/95 Eliason dated September 14, 1994
10a(15) (d) 10a(15) (d) 10a(15) Letter Agreement with Louis F. Storz dated
8/14/95 8/14/95 July 7, 1995
10a(16) (d) 10a(16) (d) 10a(16) Letter Agreement with Elbert C. Simpson dated
8/14/95 8/14/95 May 31, 1995
10a(17) (d) 10a(17) (d) 10a(17) Letter Agreement with Alfred C. Koeppe dated
11/14/95 11/14/95 August 23, 1995
10a(18) Director Stock Plan
10a(19) Mid Career Hire Supplemental Retirement Plan
10a(20) Retirement Income Reinstatement Plan
11 Inapplicable
12(a) Computation of Ratios of Earnings to Fixed
Charges
12(b) Computation of Ratios of Earnings to Fixed
Charges Plus Preferred Stock Dividend
Requirements
13 Inapplicable
16 Inapplicable
19 Inapplicable
21 Inapplicable
22 Inapplicable
23 Independent Auditors' Consent
24 Inapplicable
27 Financial Data Schedule
28 Inapplicable
99 Inapplicable