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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
---------------- ----------------
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address, and Telephone Number Identification No.
- -------------------- ---------------------------------------------------------------- ------------------------
001-00973 PUBLIC SERVICE ELECTRIC AND GAS COMPANY 22-1212800
(A New Jersey Corporation)
80 Park Plaza
P.O. Box 570
Newark, New Jersey 07101-0570
973 430-7000
http://www.pseg.com
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class Title of Each Class On Which Registered
- -------------------------------------- --------------------------------------------- -------------------------------
Cumulative Preferred Stock First and Refunding Mortgage Bonds:
$100 par value Series: Series Due
4.08% 9 1/8% BB 2005
4.18% 9 1/4% CC 2021
4.30% 8 7/8% DD 2003
5.05% 6 7/8% MM 2003
5.28% 6 1/2% PP 2004
6 1/8% RR 2002 New York Stock Exchange
7% SS 2024
7 3/8% TT 2014
6 3/4% UU 2006
6 3/4% VV 2016
6 1/4% WW 2007
6 3/8% YY 2023
8% 2037
5% 2037
Monthly Income Preferred Securities (Guaranteed Preferred Beneficial Interest
in PSE&G's Subordinated Debenture, $25 par value at 8.00%, issued by Public
Service Electric and Gas Capital, L.P. (Registrant) and registered on the New
York Stock Exchange.
Quarterly Income Preferred Securities (Guaranteed Preferred
Beneficial Interest in PSE&G's Subordinated Debentures), $25 par value at
8.125%, issued by PSE&G Capital Trust II (Registrant) and registered on the
New York Stock Exchange.
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Class
----------- --------------
Public Service Electric and Gas Company 6.92% Cumulative Preferred Stock $100 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 [ ] 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. [ ]
As of January 31, 2002, 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.
TABLE OF CONTENTS
Page
PART I
Item 1. Business............................................................................................. 1
General.............................................................................................. 1
Risk Factors......................................................................................... 2
Competitive Environment.............................................................................. 4
Regulatory Issues.................................................................................... 5
Customers............................................................................................ 9
Employee Relations................................................................................... 9
Segment Information.................................................................................. 9
Environmental Matters................................................................................ 9
Item 2. Properties........................................................................................... 10
Item 3. Legal Proceedings.................................................................................... 12
Item 4. Submission of Matters to a Vote of Security Holders.................................................. 14
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................................ 14
Item 6. Selected Financial Data.............................................................................. 14
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................ 15
Corporate Structure.................................................................................. 15
Overview of 2001 and Future Outlook.................................................................. 15
Results of Operations................................................................................ 17
Liquidity and Capital Resources...................................................................... 22
Capital Requirements................................................................................. 24
Qualitative and Quantitative Disclosures About Market Risk........................................... 25
Accounting Issues.................................................................................... 26
Forward Looking Statements........................................................................... 27
Item 7A. Qualitative and Quantitative Disclosures About Market Risk........................................... 28
Item 8. Financial Statements and Supplementary Data.......................................................... 28
Consolidated Financial Statements.................................................................... 29
Notes to Consolidated Financial Statements........................................................... 34
Financial Statement Responsibility................................................................... 51
Independent Auditors' Report......................................................................... 52
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure................. 53
PART III
Item 10. Directors and Executive Officers..................................................................... 53
Item 11. Executive Compensation............................................................................... 54
Item 12. Security Ownership of Certain Beneficial Owners and Management....................................... 59
Item 13. Certain Relationships and Related Transactions....................................................... 59
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...................................... 60
Schedule II--Valuation and Qualifying Accounts....................................................... 61
Signatures........................................................................................... 62
Exhibit Index........................................................................................ 63
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
PART I
------
ITEM 1. BUSINESS
GENERAL
Unless the context otherwise indicates, all references to "PSE&G," "we,"
"us" or "our" herein means Public Service Electric & Gas Company, a New
Jersey corporation with its principal executive offices at 80 Park Plaza,
Newark, New Jersey 07102. We are a wholly-owned subsidiary of Public Service
Enterprise Group Incorporated (PSEG) and an operating public utility company
engaged principally in the transmission and distribution of electric energy
and gas service in New Jersey. In August 2000, pursuant to the terms of the
Final Decision and Order (Final Order) issued by the New Jersey Board of
Public Utilities (BPU) under the New Jersey Energy Master Plan and the New
Jersey Electric Discount and Energy Competition Act (Energy Competition Act),
we transferred our electric generation-related assets and liabilities and our
wholesale power contracts to an affiliate, PSEG Power LLC (Power). Our
wholly-owned subsidiary, PSE&G Transition Funding LLC (Transition Funding)
was formed to issue securitization bonds in connection with the partial
recovery of our BPU approved stranded costs.
We provide electric and gas service in areas of New Jersey in which
approximately 5.5 million people, about 70% of the State's population,
reside. Our 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. This
service territory contains a diversified mix of commerce and industry,
including major facilities of many corporations of national prominence. Our
load requirements are almost evenly split among residential, commercial and
industrial customers. We believe that we have all the franchises (including
consents) necessary for our electric and gas distribution operations in the
territory we serve. Such franchise rights are not exclusive.
We distribute electric energy and gas to end-use customers within our
designated service territory. All electric and gas customers in New Jersey
have had the ability to choose an electric energy and/or gas supplier. We
supply customers that are not served by a third party supplier (TPS).
Pursuant to BPU requirements, we also serve as the supplier of last resort
for electric and gas customers within our service territory. Our revenues are
based upon tariffs approved by the BPU and the Federal Energy Regulatory
Commission (FERC) for these services (see Regulatory Issues). The demand for
electric energy and gas by our customers is affected by customer
conservation, economic conditions, weather and other factors not within our
control.
Electric Energy Supply
We have contracted with Power to provide the capacity and electricity
necessary to meet the needs of customers who do not choose a TPS. Power will
provide this basic generation service (BGS) obligation through July 31, 2002.
For each annual period thereafter, we are required to determine the BGS
supplier by competitive bid in accordance with BPU requirements. On June 29,
2001 we and the other three BPU regulated New Jersey electric utility
companies submitted a joint filing to the BPU setting forth an auction
proposal for the provision of BGS supply beginning August 1, 2002. On
December 10, 2001 the BPU approved an Internet auction to determine who will
supply BGS to utilities, which commenced on February 4, 2002. This
competitive auction covered the BGS supply requirement for the period August
1, 2002 to July 31, 2003. As conditions of qualification, applicants agreed
that if they became auction winners, they would execute the BGS Master
Service Agreement within two days of BPU Certification of the results and
they would demonstrate compliance with the credit worthiness requirements. On
February 15, 2002 the BPU approved the auction results under which we secured
contracts for our expected peak load of 9,600 megawatts (MW).
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
In addition, we purchase energy under various non-utility generation
(NUG) contracts and sell such energy to Power with the costs and proceeds
applied to the non-utility generation market transition clause (NTC) component
of our rates (see Note 4. Regulatory Assets and Liabilities of Notes to
Consolidated Financial Statements (Notes)). Rates for electricity sold in the
wholesale energy market are not subject to BPU ratemaking and are competitive
in nature. Effective August 1, 2002, we will sell the generation from the NUGs
to the wholesale market.
Gas Supply
We supplement natural gas with purchased refinery/landfill 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 of fuel
for energy production.
As of December 31, 2001, our daily gas capacity was as follows:
Type of Gas Therms Per Day
----------------------------------------------------------------- ---------------------
Natural gas.................................................... 24,379,300
Liquefied petroleum gas........................................ 2,200,000
Refinery/landfill gas.......................................... 123,000
--------------------
Total................................................. 26,702,300
=====================
About 40% of our daily gas requirements are provided through firm
transportation, which is available every day of the year. The remainder comes
from field storage, liquefied natural gas, seasonal purchases, contract
peaking supply, propane and refinery/landfill gas. Our total gas sold to and
transported to our various customer classes in 2001 was approximately 3.7
billion therms. Included in this amount were 1 billion therms of gas
delivered to customers under our transportation tariffs and individual
cogeneration contracts. During 2001, we purchased approximately 3.3 billion
therms of gas for our gas operations directly from natural gas producers and
marketers. These supplies were transported to New Jersey by four interstate
pipeline suppliers.
The majority of our gas transportation and supply contracts expire at
various times over the next 10 years. Since the quantities of gas available
to us under our supply contracts are more than adequate in warm months, we
nominate part of such quantities for storage, to be withdrawn during the
winter season when demand peaks. Underground storage capacity currently is
approximately 800 million therms. For a discussion of the transfer of our gas
supply business to Power, see Regulatory Issues-Gas Contract Transfer.
The demand for gas by our customers is affected by customer
conservation, economic conditions, weather, the price relationship between
gas and alternative fuels and other factors not within our control. Rates for
gas sold in interstate commerce are not subject to cost of service ratemaking
but are subject to competitive pricing.
We were able to meet all of the demands of our firm customers during the
2000-2001 winter season and expect to continue to meet such energy-related
demands of our firm customers during the 2001-2002 and 2002-2003 winter
seasons. However, the sufficiency of supply could be affected by several
factors not within our control, including curtailments of natural gas by our
suppliers, the severity of the winter and the availability of feedstocks for
the production of supplements to our natural gas supply. We presently do not
anticipate any difficulty in obtaining adequate supplies of natural gas over
the next several years.
RISK FACTORS
The following factors should be considered when reviewing our business,
and are relied upon by us in issuing any forward-looking statements. Such
factors could affect actual results and cause such results to differ
materially from those expressed in any forward-looking statements made by, or
on behalf of, us.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Failure to Obtain Adequate and Timely Rate Relief May Have an Adverse Impact
As a public utility, our rates are regulated by the BPU and the FERC.
These rates are designed to recover our operating expenses and allow us to
earn a fair return on our rate base, which primarily consists of our property,
plant and equipment less various adjustments. These rates include our electric
and gas tariff rates subject to regulation by the BPU as well as our
transmission rates contained in the Pennsylvania-New Jersey-Maryland Power
Pool (PJM) Open Access Transmission Tariff subject to regulation by the FERC.
Our base rates are set by the BPU for electric distribution and gas
distribution and are effective until the time a new rate case is brought to
the BPU. These base rate cases generally take place every few years. Certain
limited categories of costs, such as societal benefits and gas residential
commodity costs, are recovered through adjustment charges that are
periodically trued-up to actual costs and reset. If these costs exceed the
amount included in our adjustment charges, there will be a negative impact on
our cash flows. Our rates for electric transmission are subject to change
based on policies and procedures established by the FERC.
If our operating expenses (other than costs recovered through adjustment
charges) exceed the amount included in our base rates or in our FERC
jurisdictional rates, there will be a negative impact on earnings and
operating cash flows.
Deregulation and the Unbundling of Energy Supplies and Services and the
Establishment of a Competitive Energy Marketplace.
As a result of deregulation and the unbundling of energy supplies and
services, the gas and electric retail markets are now open to competition from
other suppliers. Increased competition from these companies could reduce the
quantity of our retail sales and have a negative impact on our cash flows.
Inability to Raise Capital on Favorable Terms to Refinance Existing
Indebtedness or to Fund Capital Commitments
Our capital is provided by equity contributions from PSEG,
internally-generated cash flows and borrowings from third parties. In order to
meet our capital requirements, we may require access to debt capital from
outside sources on acceptable terms.
We can give no assurances that our current and future capital
structure, operating performance or financial condition will permit us to
access the capital markets or to obtain other financing at the times, in the
amounts and on the terms necessary or advisable for us to successfully carry
out our business strategy or to service our indebtedness.
Changes in the Economic and Electricity and Gas Consumption Growth Rates
Our regulated rates are designed to recover our operating expenses and
earn a fair return on our rate base. These rates are based on forecasted
consumption over the period covered by the base rate cases. A decrease in
actual consumption could have a negative impact on our earnings and cash
flows. Economic conditions generally affect the amount of energy consumption.
Environmental Regulation May Limit Our Operations
We are required to comply with numerous statutes, regulations and
ordinances relating to the safety and health of employees and the public, the
protection of the environment and land use. These statutes, regulations and
ordinances are constantly changing. While we believe that we have obtained all
material environmental-related approvals required as of the date hereof to own
and operate our facilities or that such approvals have been applied for and
will be issued in a timely manner, we may incur significant additional costs
because of compliance with these requirements. Failure to comply with
environmental statutes, regulations and ordinances could have a material
effect on us, including potential civil or criminal liability and the
imposition of clean-up liens or fines and expenditures of funds to bring our
facilities into compliance.
We can give no assurance that we will be able to:
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
o obtain all required environmental approvals that we do not yet have or
that may be required in the future;
o obtain any necessary modifications to existing environmental
approvals;
o maintain compliance with all applicable environmental laws,
regulations and approvals;
o recover any resulting costs through future rates.
Delay in obtaining or failure to obtain and maintain in full force and
effect any such environmental approvals, or delay or failure to satisfy any
applicable environmental regulatory requirements, could prevent construction
of new facilities or operation of our existing facilities and could result in
significant additional cost to us.
Insurance Coverage May Not Be Sufficient
We have insurance for our facilities, including all-risk property damage
insurance and commercial general public liability insurance, in amounts and
with deductibles that we consider appropriate. We can give no assurance that
such insurance coverage will be available in the future on commercially
reasonable terms nor that the insurance proceeds received for any loss of or
any damage to any of our facilities will be sufficient to permit us to
continue to make payments on our debt. Additionally, certain properties that
we own may not be insured in the event of terrorist activity.
Recession, Acts of War or Terrorism Could Have An Adverse Impact
Consequences of the September 11, 2001 terrorist attacks on the United
States are difficult to predict. The consequences of a prolonged recession and
market conditions may include the continued uncertainty of energy prices and the
capital and commodity markets. We cannot predict the impact of any continued
economic slowdown or fluctuating energy prices; however, such impact could have
a material adverse effect on our financial condition, results of operations and
net cash flows.
Like other operators of major industrial facilities, our fuel storage
facilities and transmission and distribution facilities may be targets of
terrorist activities that could result in disruption of our ability to
distribute some portion of our energy products. Any such disruption could result
in a significant decrease in revenues and/or significant additional costs to
repair, which could have a material impact on our financial condition, results
of operations and net cash flows.
COMPETITIVE ENVIRONMENT
The regulatory structure which has historically governed the electric
and gas utility industries in the United States continues to be in
transition. Deregulation is essentially complete in New Jersey and is
complete or underway in certain other states in the Northeast and across the
United States. States have acted independently to deregulate the electric and
gas utilities. Recent experience in California, with energy shortages, high
costs and financial difficulties of utilities and the Enron bankruptcy have
caused some States to re-evaluate and, in some cases, stop the move toward
deregulation. The deregulation and restructuring of the nation's energy
markets, the unbundling of energy and related services, the diverse
strategies within the industry related to holding, buying or selling
generation capacity and the anticipated resulting industry consolidation have
had a profound effect on us, providing us with new opportunities and exposing
us to new risks (see Risk Factors and Overview of 2001 and Future Outlook of
Management's Discussion & Analysis of Financial Condition and Results of
Operations (MD&A)).
As a regulated monopoly, our electric and gas transmission and
distribution business has minimal risks from competition. Also, there has
been minimal financial impact on PSE&G's transmission and distribution
business due to customers choosing alternate electric or gas suppliers.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
REGULATORY ISSUES
State Regulation
As a New Jersey public utility, we are 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 of certain transmission facilities in Pennsylvania, we are
subject to regulation by the Pennsylvania Public Utility Commission (PPUC) in
limited respects in regard to such facilities. We are also subject to the
rules and regulations of the New Jersey Department of Environmental Protection
(NJDEP).
New Jersey Energy Master Plan Proceedings and Related Orders
Following the enactment of the Energy Competition Act, the BPU rendered its
Final Order relating to our rate unbundling, stranded costs and restructuring
proceedings providing, among other things, for the transfer to an affiliate of
all of our electric generation facilities, plant and equipment for $2.443
billion and all other related property, including materials, supplies and fuel
at the net book value thereof, together with associated rights and liabilities.
Pursuant to the Final Order, we transferred our electric generating facilities
and wholesale power contracts to Power and its subsidiaries on August 21, 2000
in exchange for a promissory note from Power in an amount equal to the purchase
price of $2.786 billion. Power paid the promissory note on January 31, 2001 at
which time the transferred assets were released from the lien of our First and
Refunding Mortgage.
The Energy Competition Act and the related BPU proceedings, including
the Final Order, referred to as the Energy Master Plan Proceedings, opened
the New Jersey energy markets to competition by allowing all New Jersey
retail electric and gas customers to select their suppliers. For further
discussion of the Energy Master Plan Proceedings, see Note 3. Regulatory
Issues and Accounting Impacts of Deregulation of Notes.
In accordance with the Final Order, we reduced customer rates initially
by 5%, an additional 2% after the securitization transaction in February of
2001 and another 2% in August 2001. We are scheduled to reduce rates another
4.9% in August 2002, for a total 13.9% rate reduction since August 1999.
These rate reductions reduce the market transition charge (MTC) revenue that
we remit to Power as part of the BGS contract.
BGS Auction
The BPU approved an auction to identify energy suppliers for our BGS
obligation beginning on August 1, 2002. On February 15, 2002 the BPU approved
the BGS auction results and we secured contracts from a number of suppliers
for our expected peak load of 9,600 MW. We will pay $.0511 per kWh to obtain
electricity for customers for the period August 1, 2002 to July 31, 2003.
Customers will continue to pay below-market regulated rates (BGS shopping
credit) for this one-year period. Under our current rate structure, the
difference will be deferred and recovered with interest in the future. We
will sell the power we receive from NUG contracts into the wholesale energy
market, which should offset this underrecovery. We estimate that the
underrecovery relating to the BGS for the period ending July 31, 2003 will
amount to approximately $250 million with a net amount of $125 million after
factoring in sales of power relating to NUG contracts.
If a supplier defaults on its obligation to provide energy to us or if our
peak load exceeds our contracted supply, the energy needed for us to meet our
requirements will be purchased at market prices in accordance with the
procedures approved by the BPU. To the extent that the market prices exceed the
auction contract price, the difference will be deferred and collected from our
customers as provided in the BPU Order approving the auction process.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Electric Base Rate Case
In accordance with the Final Order, we expect to file an electric base
rate case during 2002 that would be effective on August 1, 2003. This case
may impact our earnings and cash flows; however, we cannot predict the actual
effects at this time.
Affiliate Standards
In February 2000, the BPU approved affiliate standards and fair
competition standards which apply to transactions between a public utility
and those of its affiliates that provide competitive services to retail
customers in New Jersey. On March 15, 2000, the BPU issued a written order
(Affiliate Standards) related to these matters. We filed a compliance plan on
June 15, 2000 to describe the internal policy and procedures necessary to
ensure compliance with such Affiliate Standards. The BPU has conducted an
audit of New Jersey utilities' competitive activities and compliance with
such Affiliate Standards and is expected to issue an order on the audit in
2002. The adoption of Affiliate Standards did not have a material adverse
effect on our financial condition, results of operations or net cash flows.
Gas Unbundling
The Energy Competition Act also required that all customers have the
ability to choose a competitive gas supplier. During 2000, the BPU issued a
written order providing for the unbundling of firm rate schedules into
commodity and transportation components and for changes in existing rate
schedules. The new rates were implemented for all service provided on and
after August 1, 2000.
The main features of the gas unbundling are: the development of a
Societal Benefits Clause (SBC) to recover specific costs including, social
programs, Demand Side Management costs (DSM), a Remediation Adjustment Clause
(RAC) and consumer education; the development of a Realignment Adjustment
Charge to recover lost revenues incurred by us (subject to certain criteria)
as a result of customers switching from commodity service to transportation
service; the reallocation of approximately $40 million from transportation
rates to commodity and balancing rates; an incentive of approximately 0.9
cents per therm for all customers who leave us to shop with a TPS and an
additional incentive of 1.4 cents per therm for residential customers who
leave us to shop with a TPS.
Gas Contract Transfer
On August 11, 2000, we filed a gas merchant restructuring plan with the
BPU. On January 9, 2002, the BPU approved an amended stipulation, which
permitted the transfer of our gas supply business, including our interstate
capacity, storage and gas supply contracts to a subsidiary of Power, which will,
under a requirements contract, provide the gas supply to us to serve our Basic
Gas Supply Service (BGSS) customers.
The gas contract transfer is expected to reduce volatility in our cash
flows. Gas residential commodity costs are currently recovered through
adjustment charges that are periodically trued-up to actual costs and reset.
After the transfer, we will pay Power the amount we charge our gas distribution
customers for the commodity. Industrial and commercial BGSS customers will be
priced under our Market Priced Gas Service (MPGS). Residential BGSS customers
will remain under current pricing until April 1, 2004 after which, subject to
further BPU approval, those residential gas customers would also move to MPGS
service.
Gas Base Rate Case and Commodity Charges
The BPU has granted us authority to change the Monthly Pricing Mechanism
(MPM) in our Levelized Gas Adjustment Clause (LGAC) to cover currently
estimated gas price increases on a per month basis, exercisable in any month
without an annual limit.
In May 2001, we filed a petition with the BPU for authority to revise
our gas property depreciation rates (Depreciation Case). In this filing, we
requested authority to implement our proposed depreciation rates
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
simultaneously for book purposes and ratemaking purposes when the BPU
implements new tariffs designed to recover the additional annual revenues
resulting from the gas base rate case discussed below.
Also in May 2001, we filed a petition with the BPU requesting an
increase in gas base rates of $171 million for gas delivery service (Gas Base
Rate Case). The requested increase was for an overall gas revenue increase of
7.06% to reflect current costs. We filed the Gas Base Rate Case because the
gas base rates, in effect since November 1991, did not reasonably reflect
capital investments and other costs required to maintain the gas utility
infrastructure. The BPU consolidated the Depreciation Case and the Gas Base
Rate Case.
In November 2001, we filed and served our 2001 LGAC filing, requesting
approximately a 10% reduction. We requested that such filing be retained by
the BPU and implemented simultaneously with the order in the Gas Base Rate
Case. Also in November 2001, we made a compliance filing with the BPU to
implement an approximate 3% increase through the Gas Cost Underrecovery
Adjustment (GCUA) surcharge effective December 1, 2001. This surcharge is
designed to recover our October 2001 gas underrecovery balance of $130
million. In January 2002, the BPU issued an order approving the increase.
In January 2002, the BPU issued an order approving a Settlement under which
we will receive an additional $90 million of gas base rate revenues,
approximately $8 million of which results from gas depreciation rate changes.
This occured simultaneously with the implementation of our compliance filing to
implement our previously approved GCUA surcharge to recover our October 31, 2001
gas cost underrecovery balance of approximately $130 million over a three-year
period with interest and the reduction of our 2001-2003 Commodity Charges
(formerly LGAC) by approximately $140 million. All three rate changes became
effective on January 9, 2002.
The $8 million gas depreciation rate changes are due primarily to the
shortening of the useful lives for general plant and equipment. This
adjustment will have no impact on earnings, as it will be offset by increased
operating cash flows in a normal business environment. Assuming current cost
levels and a normal business environment, the $82 million balance of our gas
base rate increase will have a positive impact on earnings and operating cash
flows. The settlement set our gas rate base at approximately $1.6 billion,
our rate of return on this rate base at 8.27% and our cost of capital or
total return on equity of our gas operations at 10%. As a result of the
settlement, we agreed not to request another gas base rate increase that
would take effect prior to September 1, 2004.
The $130 million rate increase relating to the GCUA will have no impact
on earnings and will increase operating cash flows in a normal business
environment. The reduction in our 2001-2003 commodity charges relates to our
residential customers and will have no impact on earnings and will decrease
operating cash flows assuming current cost levels and a normal business
environment.
Focused Audit
For information regarding the 1992 BPU proceeding concerning the
relationship of us to PSEG's non-utility businesses (Focused Audit), see
Liquidity and Capital Resources of MD&A.
Federal Regulation
Our operations are subject to regulation by the FERC with respect to
certain matters, including interstate sales and exchanges of electric
transmission, capacity and energy.
FERC RTO Orders and PJM Interconnection LLC (PJM)
In December 1999, FERC promulgated a Final Rule (Order 2000) in the
Regional Transmission Organization (RTO) rulemaking proceeding. In October
2000, PJM and nine PJM transmission owners, including us, made a filing with
FERC stating that PJM is an RTO that meets or exceeds the requirements of
Order 2000. Included in this filing was a PJM rate proposal designed to
provide for deferral recovery of reasonable, risk-adjusted returns on new
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
transmission investments in the PJM region, an accelerated recovery period for
such new investments, and a rate moratorium of current charges through
December 31, 2004.
In July 2001, FERC issued a series of orders that, amongst other things,
rejected the rate design proposal, established generation interconnection
proceedings and called for the creation of four large regional transmission
organizations (RTOs) to facilitate competitive regional markets in the U.S.
FERC rejected several smaller RTO proposals and directed transmission owners
and independent system operators (ISOs) to combine into much larger RTOs,
dramatically altering their proposed geographic size and configuration. In
August 2001, the PJM transmission owners requested a rehearing of the PJM RTO
Order. The matter is still pending.
In the Northeast region, FERC conditionally approved the PJM RTO
proposal (subject to several modifications and compliance filings) and
rejected the New York ISO and ISO-New England RTO proposals. FERC directed
that the three existing ISOs for PJM, New York and New England, as well as
the systems involved in PJM West, form a single Northeast RTO, based on the
"PJM platform" and "best practices" of all three ISO's. FERC directed that
the parties in the region engage in mediation (with FERC oversight) to
prepare a proposal and timetable for the merger of the ISOs into a single
RTO. At the end of the 45-day mediation period, the Administrative Law Judge
assigned to the matter submitted a report to the Commission with an attached
business plan for implementation of the single northeast RTO possibly as soon
as the fourth quarter of 2003.
In January 2002, PJM and the Midwest ISO announced that they had entered
into negotiations to create a virtual uniform seamless market encompassing
their two RTOs, shortly after the FERC approved the Midwest ISO as an RTO. In
addition, ISO New England and the New York ISO agreed to jointly develop a
common electricity market and evaluate a New England - New York RTO.
FERC has started a series of conferences to discuss the technical issues
related to its consideration of a standard market design - products and
protocols - for wholesale electric power markets. The goal of these
conferences is to gain a mutual understanding of similarities and differences
between various market designs and to allow participants to provide further
detail on market operations. We have been supportive of the incorporation of
both capacity and spot energy markets as part of any standardized market
design. The information from these conferences will be used to issue a formal
Notice of Proposed Rulemaking (NOPR) on a standard market design later this
year.
FERC issued an advance notice of proposed rulemaking seeking comments to
help form the basis for a proposed rule to standardize power-plant
interconnection requirements to ease market entry for new generation. FERC
also will, as part of the rulemaking, reconsider its policy addressing how
transmission owners treat the cost of system upgrades necessary to
accommodate new generation, potentially resulting in a new methodology. The
ultimate outcome of this rulemaking and its impact upon us cannot be
predicted.
The impact of these developments on us is uncertain because specific
rules will not be known for some time and are subject to FERC approval, which
cannot be assured.
Other Regulatory Issues
Tax Sharing Agreement
The issue of PSEG sharing the benefits of consolidated tax savings with
us or our customers was addressed by the BPU in 1995 in a letter which
informed us that the issue of consolidated tax savings can be discussed in
the context of a future base rate case or plan for an alternative form of
regulation. PSEG believes that our taxes should be treated on a stand-alone
basis for ratemaking purposes, based on the separate nature of the utility
and non-utility
8
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
businesses. Neither PSEG nor we are able to predict what action,
if any, the BPU may take concerning consolidated tax savings in future
proceedings.
CUSTOMERS
As of December 31, 2001, we provided service to approximately 2.0
million electric customers and approximately 1.6 million gas customers. Our
service territory contains a diversified mix of commerce and industry. Our
load requirements are almost evenly split among residential, commercial and
industrial customers.
EMPLOYEE RELATIONS
As of December 31, 2001, we had 6,554 employees, 5,033 of which are
union members. We have a three-year collective bargaining agreement in place
with three of our union groups, covering 3,636 employees, which expires on
April 30, 2005. We also have a collective bargaining agreement with the
Utility Co-Workers Association, covering 1,397 employees, that expires on
April 30, 2002 and plan to negotiate a new agreement, which cannot be
assured. We believe that we maintain satisfactory relationships with our
employees.
For information concerning employee pension plans and other
postretirement benefits, see Note 10. Pension, Other Postretirement Benefit
and Savings Plans of Notes.
SEGMENT INFORMATION
Financial information with respect to our business segments is set forth
in Note 11. Financial Information by Business Segments of Notes.
ENVIRONMENTAL MATTERS
Federal, regional, state and local authorities regulate the
environmental impacts of our operations. Areas of regulation include air
quality, water quality, site remediation, land use, waste disposal,
aesthetics and other matters.
Compliance with environmental requirements has caused us to modify the
day-to-day operation of our facilities, to participate in the cleanup of
various properties that have been contaminated and to modify, supplement and
replace existing equipment and facilities. During 2001, we expended
approximately $4 million for capital related expenditures to improve the
environment and comply with laws and regulations and estimate that we will
expend approximately $9 million, $5 million and $2 million in the years 2002
through 2004, respectively, for such purposes.
Control of Hazardous Substances
Manufactured Gas Plant Remediation Program
For information regarding our Manufactured Gas Plant Remediation
Program, see Note 8. Commitments and Contingent Liabilities of Notes.
Hazardous Substances
Certain Federal and state laws authorize the Environmental Protection
Agency (EPA) and the NJDEP, among other agencies, to issue orders and bring
enforcement actions to compel responsible parties to investigate and take
remedial actions at any site that is determined to present an actual or
potential threat to human health or the environment because of an actual or
threatened release of one or more hazardous substances. Because of the
nature of
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
our businesses, including the distribution of gas and, formerly, the
manufacture of gas and production of electricity, various by-products and
substances are or were produced or handled which contain constituents
classified by Federal and State authorities as hazardous. For discussions of
these hazardous substance issues and a discussion of potential liability for
remedial action regarding the Passaic River, see Note 8. Commitments and
Contingent Liabilities. For a discussion of remediation/clean-up actions
involving us, see Item 3. Legal Proceedings.
Other liabilities associated with environmental remediation include
natural resource damages. The Federal Comprehensive Environmental Response,
Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill
Compensation and Control Act (Spill Act) authorize Federal and state trustees
for natural resources to assess "damages" against persons who have discharged
a hazardous substance, which discharge resulted in an "injury" to natural
resources. Until recently, the State trustee, NJDEP, has not aggressively
pursued natural resource damages. In 1997, the NJDEP adopted changes to the
Technical Requirements for Site Remediation pursuant to the Spill Act. Among
these changes was a new provision requiring all persons conducting
remediation to characterize "injuries" to natural resources. Further, these
changes required persons to address those injuries through restoration or
damages. We cannot assess the magnitude of the potential impact of this
regulatory change. Although not currently estimable, these costs could be
material.
The EPA has determined that a six mile stretch of the Passaic River in
the area of Newark, New Jersey is a facility within the meaning of that term
under the CERCLA and that, to date, at least thirteen corporations, including
us, may be potentially liable for performing required remedial actions to
address potential environmental pollution at the Passaic River facility. We
have one former electric plant and four former manufactured gas plants within
the Passaic River "facility". We cannot predict what action, if any, the EPA
or any third party may take against us with respect to these matters, or in
such event, what costs we may incur to address any such claims. However, such
costs may be material.
The EPA conducted an inspection of Spill Prevention Control and
Countermeasure (SPCC) Plan compliance at three of our substation facilities
in 1997. The EPA identified certain procedural and substantive deficiencies
in the SPCC Plans for these sites. We have submitted revised SPCC Plans to
the EPA for these sites and are currently working with the EPA to finalize
these SPCC Plans. In 1998, we evaluated SPCC Plan compliance at all of SPCC
substations and identified deficiencies. The necessary upgrades are now in
the process of being made. It is anticipated that these upgrades will take
several years to complete.
Uranium Enrichment Decontamination and Decommissioning Fund
In accordance with the Energy Policy Act (EPAct), domestic entities that
own nuclear generating stations are required to pay into a decontamination
and decommissioning fund, based on their past purchases of U.S. government
enrichment services. Since these amounts are being collected from our
customers over a period of 15 years, this obligation remained with us
following the generation asset transfer to Power in 2000. Under this
legislation, our original obligation for the nuclear generating stations in
which we had an interest was $73 million (adjusted for inflation). Since
1993, $48 million has been paid, approximately $5 million annually, resulting
in a balance due of $25 million. We believe that we are not subject to
collection of any such fund payments under the EPAct. Along with other
nuclear generator owners, we have filed suit in the U.S. Court of Claims and
in the U.S. District Court, Southern District of New York to recover these
costs.
ITEM 2. PROPERTIES
Our First and Refunding Mortgage (Mortgage), securing the bonds issued
thereunder, constitutes a direct first mortgage lien on substantially all of
our property.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Our electric lines and gas mains are located over or under public
highways, streets, alleys or lands, except where they are located over or
under property owned by us or occupied by us under easements or other rights.
These easements and rights are deemed by us to be adequate for the purposes
for which they are being used.
We believe that we maintain insurance coverage against loss or damage to
our principal properties, subject to certain exceptions, to the extent such
property is usually insured and insurance is available at a reasonable cost.
Electric Transmission and Distribution Properties
As of December 31, 2001, our transmission and distribution system
included approximately 21,760 circuit miles, of which approximately 6,363
miles were underground, and approximately 836,068 poles, of which
approximately 536,780 poles were jointly owned. Approximately 99% of this
property is located in New Jersey.
In addition, as of December 31, 2001, we owned five electric
distribution headquarters and four subheadquarters in four operating
divisions, all located in New Jersey.
Gas Distribution Properties
As of December 31, 2001, the daily gas capacity of our 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 2,886,000
cubic feet on an equivalent basis of 1,030 Btu/cubic foot) as shown in the
following table:
Daily Capacity
Plant Location (Therms)
- ----- -------- --------
Burlington LNG.................................. Burlington, NJ 773,000
Camden LPG...................................... Camden, NJ 280,000
Central LPG..................................... Edison Twp., NJ 960,000
Harrison LPG.................................... Harrison, NJ 960,000
---------------
Total..................................... 2,973,000
===============
As of December 31, 2001, we owned and operated approximately 16,888
miles of gas mains, owned 11 gas distribution headquarters and two
subheadquarters all in two operating regions located in New Jersey and owned
one meter shop in New Jersey serving all such areas. In addition, we 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 us with natural gas and were operated under lease,
easement or other similar arrangement. In some instances, the pipeline
companies owned portions of the metering and regulating facilities.
Office Buildings and Facilities
We lease substantially all of a 26-story office tower for our corporate
headquarters at 80 Park Plaza, Newark, New Jersey, together with an adjoining
three-story building. We also lease other office space at various locations
throughout New Jersey for district offices and offices for various corporate
groups and services. We also own various other sites for training, testing,
parking, records storage, research, repair and maintenance, warehouse
facilities and for other purposes related to our business.
In addition to the facilities in New Jersey and Pennsylvania as
discussed above, as of December 31, 2001, we owned 39 switching stations in
New Jersey with an aggregate installed capacity of 30,417,670
kilovolt-amperes and 249 substations with an aggregate installed capacity of
7,446,000 kilovolt-amperes. In addition, six substations in New Jersey having
an aggregate installed capacity of 108,000 kilovolt-amperes were operated on
leased property.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
ITEM 3. LEGAL PROCEEDINGS
See information on the following regulatory proceedings at the pages
indicated:
(1) Pages 5, 15, 16, 38 and 39. Proceedings before the BPU in the
matter of the Energy Master Plan Phase II Proceeding to investigate
the future structure of the Electric Power Industry, Docket Nos.
EX94120585Y, EO97070461, EO97070462, EO97070463, and EX01050303.
(2) Pages 6 and 7 regarding our Gas Base Rate Filings, Docket Nos.
GR01050328 and GR01050297.
(3) Page 10 regarding the DOE not taking possession of spent nuclear
fuel, Docket No. 01-551C.
(4) Pages 9 and 46 regarding our MGP Remediation Program.
(5) Page 46 Investigation and additional investigation by the EPA
regarding the Passaic River site. Docket No. EX93060255.
In addition, see the following environmental related matters involving
governmental authorities. Based on current information, we do not expect
expenditures for any such site, individually or all such current sites in the
aggregate, to have a material effect on our financial condition, results of
operations and net cash flows.
(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 our knowledge there has been no
action on this matter since 1988.
(2) Duane Marine Salvage Corporation Superfund Site is in Perth
Amboy, Middlesex County, New Jersey. The EPA had named PSE&G
as one of several potentially responsible parties (PRPs)
through a series of administrative orders between December
1984 and March 1985. Following work performed by the PRPs, the
EPA declared on May 20, 1987 that all of its administrative
orders had been satisfied. The NJDEP, however, named us as a
PRP and issued its own directive dated October 21, 1987.
Remediation is currently ongoing.
(3) Various Spill Act directives were issued by NJDEP to PRPs,
including us with respect to the PJP Landfill in Jersey City,
Hudson County, New Jersey, ordering payment of costs associated
with operating and maintenance expenses, interim remedial
measures and a Remedial Investigation and Feasibility Study
(RI/FS) in excess of $25 million. The directives also sought
reimbursement of NJDEP's past and future oversight costs and the
costs of any future remedial action.
(4) Claim by the EPA, Region III, under CERCLA with respect to a
Cottman Avenue Superfund Site, a former non-ferrous scrap
reclamation facility located in Philadelphia, Pennsylvania,
owned and formerly operated by Metal Bank of America, Inc. We,
other utilities and other companies are alleged to be liable
for contamination at the site and we have been named as a PRP.
A 60% Complete Remedial Design document was submitted to the
EPA in March 2001. This document presents the design details
that will implement the EPA selected remediation remedy. The
costs of remedy implementation are estimated to range from $14
million to $24 million. Our share of the remedy implementation
costs is estimated between $4 million and $8 million.
Additionally, with respect to this site, the United States of
America application in the matter entitled United States of
America, et. al., v. Union Corporation, et. al., Civil Action
No. 80-1589, United States District Court for the Eastern
District of Pennsylvania, seeking leave of court to file an
amended complaint adding claims under the CERCLA was granted.
One other utility and us were named as third party defendants
in the foregoing captioned matter. An application to intervene
in the captioned matter as third party defendants, filed by
seven other utilities alleged to be liable for contamination
at the Site, has also been granted by the Court.
(5) The Klockner Road site is located in Hamilton Township, Mercer
County, New Jersey, and occupies approximately two acres on our
Trenton Switching Station property. We have entered into a
memorandum of agreement (MOA) with the NJDEP for the Klockner
Road site pursuant to which we will conduct an RI/FS and remedial
action, if warranted, of the site. Preliminary investigations
indicated the potential presence of soil and groundwater
contamination at the site.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(6) In 1991, the NJDEP issued Directive and Notice to Insurers
Number Two (Directive Two) to 24 Insurers and 52 Respondents,
including us, in connection with an investigation and
remediation of the Global Landfill Site in Old Bridge
Township, Middlesex County, New Jersey seeking recovery of
past and anticipated future NJDEP response costs ($37
million). Other participating PRPs and us have agreed with
NJDEP to a partial settlement of such costs and to perform the
remedial design and remedial action. In 1996, 13 of the
Directive Two Respondents, including us, filed a contribution
action pursuant to CERCLA and the Spill Act against
approximately 190 parties seeking contribution for an
equitable share of all liability for response costs incurred
and to be incurred in connection with the site. In September
1997, the NJDEP issued a Superfund record of decision (ROD)
with estimated cost of $3.7 million. The Directive Two
Respondents' foregoing contribution claims have been resolved
by settlement.
(7) In 1991, the NJDEP issued Directive and Notice To Insurers
Number One (Directive No. One) to 50 insurers and 20
respondents, including us, 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 NJDEP's 10% share of total estimated site
remediation costs and administrative oversight costs pursuant
to a cooperative agreement with the United States concerning
the selected remedial action for the site. In 1996, the NJDEP
issued Directive Number Two (Directive No. Two) to 37
respondents, including us, directing the respondents to
arrange for the operation, maintenance and monitoring of the
implemented remedial action described therein or pay the
NJDEP's future costs of these activities, estimated to be $39
million. In addition, Directive No. Two directs the
respondents to prepare a work plan for the development and
implementation of a Natural Resource Damage Restoration Plan.
In October 1998, the NJDEP and The United States of America
filed separate cost recovery actions pursuant to CERCLA and/or
the Spill Act against approximately 30 parties seeking
recovery of their respective shares of past and future site
investigation and remediation response and administrative
oversight costs incurred and to be incurred at the site. Third
party contribution actions were also filed in each of the
foregoing cost recovery actions seeking contribution for an
equitable share of all liability for these same costs from
approximately 170 third party defendants. We are named as a
defendant in the NJDEP cost recovery action and a named third
party defendant in the contribution action filed in the United
States' lawsuit.
(8) Spill Act Multi-Site Directive (Directive) issued by the NJDEP to
PRPs, including us, listing four separate sites, including the
former solid waste 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 us, to
enter into an Administrative Consent Order (ACO) with NJDEP,
requiring to remediate the Sewell Site. We and certain other de
minimis parties have accepted a settlement offer in 2001 from
other PRPs to resolve our liability for response and removal
costs at the site.
(9) The New York State Department of Environmental Conservation
(NYSDEC) has named us as one of many potentially responsible
parties for contamination existing at the former Quanta Resources
Site in Long Island City, New York. Waste oil storage,
processing, management and disposal activities were conducted at
the site from approximately 1960 to 1981. It is believed that
waste oil from our and Power's current and former facilities was
taken to the Quanta Resources Site. NYSDEC has requested that the
potentially responsible parties reimburse the state for the costs
NYSDEC has expended at the site and to conduct an investigation
and remediation of the site. We and the other PRPs are
negotiating with NYSDEC the terms of an agreement that will set
forth these requirements, and are negotiating among ourselves an
agreement for the sharing of the associated costs.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS
Inapplicable.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
All of our common stock is owned by PSEG.
ITEM 6. SELECTED FINANCIAL DATA
The information presented below should be read in conjunction with our
Consolidated Financial Statements and Notes thereto.
Years Ended December 31,
----------------------------------------------------------------
2001 2000 1999 1998 1997
------------ ------------ ----------- ------------ --------
(Millions of Dollars, where applicable)
Total Operating Revenues........................... $6,091 $7,359 $7,640 $7,422 $6,103
Income Before Extraordinary Item................... $235 $587 $653 $602 $528
Extraordinary Item (A)............................. -- -- (804) -- --
Net Income (Loss).................................. $235 $587 $(151) $602 $528
As of December 31:
Total Assets.................................... $12,936 $15,267 $14,724 $14,669 $14,844
Long-Term Liabilities:
Long-Term Debt (B)............................ $4,977 $3,590 $3,099 $4,045 $4,127
Other Noncurrent Liabilities (C).............. $725 $690 $1,535 $741 $586
Preferred Stock With Mandatory Redemption.......... $75 $75 $75 $75
--
Monthly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures................. $60 $210 $210 $210 $210
Quarterly Guaranteed Preferred Beneficial Interest
in PSE&G's Subordinated Debentures.............. $95 $303 $303 $303 $303
Ratio of Earnings to Fixed Charges (D)............. 1.83 3.15 3.58 3.27 2.74
Ratio of Earnings to Fixed Charges plus Preferred
Securities Dividend Requirements (D)............ 1.79 3.04 3.46 3.15 2.64
(A) See Note 3. Regulatory Issues and Accounting Impacts of Deregulation.
(B) Increase in debt related to the securitization transaction in 2001.
(C) Excludes Deferred Income Taxes, ITC and the Excess Depreciation Reserve
portion of Regulatory Liabilities.
(D) Excludes income and expenses from Extraordinary Item.
14
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Unless the context otherwise indicates, all references to "PSE&G," "we,"
"us" or "our" herein means Public Service Electric & Gas Company (PSE&G), a
New Jersey corporation with its principal executive offices at 80 Park Plaza,
Newark, New Jersey 07102. This discussion makes reference to our Consolidated
Financial Statements and related Notes to the Consolidated Financial
Statements (Notes) and should be read in conjunction with such statements and
notes.
CORPORATE STRUCTURE
We are a wholly-owned subsidiary of Public Service Enterprise Group
Incorporated (PSEG), we are an operating public utility company engaged
principally in the transmission and distribution of electric energy and gas
service in New Jersey. On August 21, 2000, pursuant to the terms of the Final
Order issued by the New Jersey Board of Public Utilities (BPU) under the New
Jersey Energy Master Plan (Energy Master Plan Proceedings) and the New Jersey
Electric Discount and Energy Competition Act (Energy Competition Act), we
transferred our electric generation-related assets and liabilities and our
wholesale power contracts to our affiliate, PSEG Power LLC (Power) and its
subsidiaries in exchange for a promissory note in an amount equal to the total
purchase price of $2.786 billion. Power paid the promissory note on January 31,
2001 at which time the transferred assets were released from the lien of our
First and Refunding Mortgage. We continue to own and operate our regulated
electric and gas transmission and distribution business.
Our bankruptcy-remote subsidiary, PSE&G Transition Funding LLC
(Transition Funding), issued $2.525 billion of securitization bonds in
January of 2001 in partial recovery of our stranded cost resulting from New
Jersey deregulation and restructuring. An additional $540 million of our
stranded costs is being recovered from our customers over a four-year
transition period ending July 31, 2003 through a Market Transition Charge
(MTC).
OVERVIEW OF 2001 AND FUTURE OUTLOOK
The electric and gas utility industries in the United States and around
the world continue to experience significant change. Deregulation,
restructuring, privatization and consolidation are creating new and different
opportunities and risks for us. Our success will depend upon our ability to
obtain adequate and timely rate relief, control our costs and provide
reliable, safe service.
The Energy Competition Act and the related BPU proceedings, including
the Final Order, have dramatically reshaped the utility industry in New
Jersey and have directly affected how we will conduct business, and
therefore, our financial prospects in the future.
We operate under cost-based regulation by the BPU for our distribution
operations and by the Federal Energy Regulatory Commission (FERC) for our
electric transmission operations. As such, our earnings are largely determined
by the regulation of our rates. We expect to continue to have steady earnings in
the future as we continue our transmission and distribution of electric energy
and gas service in New Jersey. Our success will be determined by our ability to
maintain system reliability and safety, effectively manage costs and obtain
timely and adequate rate relief. The risks from this business are relatively
modest and generally relate to the regulatory treatment of the various rate and
other issues by the BPU and the FERC.
In the Final Order, the BPU concluded that we should recover up to $2.94
billion (net of tax) of our generation-related stranded costs, through
securitization of $2.4 billion and an opportunity to recover up to $540 million
(net of tax) of our unsecuritized generation-related stranded costs on a net
present value basis through a market transition charge (MTC). Following the
issuance of the Final Order, the BPU issued its Finance Order approving, among
other things, the issuance and sale of $2.525 billion of transition bonds,
including an estimated $125 million of transaction costs, by Transition Funding.
On January 31, 2001, Transition Funding purchased our property right in the
securitization transition charge (STC) and remitted the proceeds of the issuance
of the transition bonds as consideration for such property right. We used these
proceeds to retire a portion of our outstanding debt and equity. In accordance
with the Final Order, we reduced customer rates initially by 5%, an additional
2% after the securitization transaction in February 2001 and another 2% in
August 2001. We are scheduled to reduce rates by 4.9% in August 2002, for a
total 13.9% rate reduction since August 1999. These rate reductions are
reflected in the MTC rate charged to customers. Since the MTC revenue is
remitted to power, our earnings are not impacted by these rate reductions. As a
result of the generation asset transfer, our earnings and cash flows have been
and will continue to be lower than those in periods prior to the transfer.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
We have contracted with Power to provide the capacity and electricity
necessary to meet the energy needs of customers who have not chosen an
alternate third party supplier (TPS). Power will provide this basic
generation service (BGS) obligation through July 31, 2002. Under this
contract, we pay a fixed amount to Power that equals the amount we collect
from customers; therefore, there is no impact to earnings. For each annual
period after July 31, 2002, we are required to determine the BGS supplier by
competitive bid in accordance with BPU requirements. On June 29, 2001 we and
the other three regulated New Jersey electric utility companies submitted a
joint filing to the BPU setting forth an auction proposal for the provision
of BGS supply beginning August 1, 2002. On December 10, 2001 the BPU approved
an Internet auction to determine who will supply BGS to utilities, which was
held on February 4, 2002.
On February 15, 2002 the BPU approved the BGS auction results and we
secured contracts from a number of suppliers for our expected peak load of 9,600
megawatts (MW). We will pay $.0511 per kWh to obtain electricity for customers
for the period August 1, 2002 to July 31, 2003. Customers will continue to pay
below-market regulated rates (BGS shopping credit) for this one-year period.
Under our current rate structure, the difference will be deferred and recovered
with interest in the future. We will sell the power we receive from NUG
contracts into the wholesale energy market, which should offset this
underrecovery. We estimate that the underrecovery relating to the BGS for the
period ending July 31, 2003 will amount to approximately $250 million with a net
amount of $125 million after factoring in sales of power relating to NUG
contracts.
If a supplier defaults on its obligation to provide energy to us or if our
peak load exceeds our contracted supply, the energy needed for us to meet our
requirements will be purchased at market prices in accordance with the
procedures approved by the BPU. To the extent that the market prices exceed the
auction contract price, the difference will be deferred and collected from our
customers as provided in the BPU Order approving the auction process.
In accordance with the Final Order, we expect to file an electric base
rate case during 2002 that would be effective on August 1, 2003. This case
may impact our earnings and cash flows; however, we cannot predict the actual
effects at this time.
In January 2002, the BPU issued an order approving a Settlement under
which we will receive an additional $90 million of gas base rate revenues,
approximately $8 million of which results from gas depreciation rate changes.
This occurred simultaneously with the implementation of our compliance filing
to implement our previously approved GCUA surcharge to recover our October
31, 2001 gas cost underrecovery balance of approximately $130 million over a
three-year period with interest and the reduction of our 2001-2003 Commodity
Charges (formerly LGAC) by approximately $140 million. All three rate changes
became effective on January 9, 2002.
The $8 million gas depreciation rate changes are due primarily to the
shortening of the useful lives on our other gas plant assets. This adjustment
will have no impact on earnings and will result in increased operating cash
flows in a normal business environment. Assuming current cost levels and a
normal business environment, the $82 million balance of our gas base rate
increase will have a positive impact on earnings and operating cash flows.
The settlement set our gas rate base at approximately $1.6 billion, our rate
of return on this rate base at 8.27% and our cost of capital or total return
on equity of our gas operations at 10%. As a result of the settlement, we
agreed that gas base rates would not be increased until at least September 1,
2004.
The $130 million rate increase relating to the GCUA will have no impact
on earnings and will increase operating cash flows in a normal business
environment. The reduction in our 2001-2003 commodity charges relates to our
residential customers and will have no impact on earnings and will decrease
operating cash flows assuming current cost levels and a normal business
environment.
On August 11, 2000, we filed a gas merchant restructuring plan with the BPU
which provides for, among other things, the transfer of our gas supply business,
including our transportation, storage and peaking contracts to a subsidiary of
Power and a requirements contract between us and Power's subsidiary enabling us
to fulfill our basic gas supply service. On January 9, 2002, the BPU approved
this transfer and a Requirements Contract to provide the gas supply
16
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
to us to serve our Basic Gas Supply Service (BGSS) customers. The transfer is
anticipated to take place in April 2002.
The gas supply transfer is expected to reduce volatility in our cash flows.
Gas residential commodity costs are currently recovered through adjustment
charges that are periodically trued-up to actual costs and reset. After the gas
contract transfer, Power will charge us for the amount we recover from gas
distribution customers. Industrial and commercial BGSS customers will be priced
under our Market Priced Gas Service (MPGS). Residential BGSS customers will
remain under current pricing until April 1, 2004 after which, subject to further
BPU approval, those residential gas customers would also move to MPGS service.
To the extent that the discussion that follows reports on business
conducted under full monopoly regulation of the utility businesses, it must
be understood that such businesses have changed due to the deregulation of
the electric generation and natural gas commodity sales businesses and the
subsequent sale of the generation business to Power. Past results are not an
indication of future business prospects or financial results.
RESULTS OF OPERATIONS
For the Year Ended December 31, 2001 compared to the Year Ended December 31,
2000
Operating Revenues
Electric Transmission and Distribution
Transmission and Distribution revenues increased $34 million or 2% in
2001 as compared to 2000 primarily due to the effects of weather and overall
sales growth.
Power Supply
Power Supply revenues increased approximately $1.2 billion in 2001 as
compared to 2000 primarily due to the generation asset transfer to Power in
August 2000. These revenues represent the BGS and MTC tariff rates charged by us
to our customers who are not served by another supplier and Non-Utility
Transition Charge (NTC) rates charged by us to our customers to recover the
above market costs related to energy purchased by us under various NUG
Contracts. Power Supply revenues in 2001 also include sales to Power of energy
purchased under the NUG contracts. These sales are made to Power at the
locational marginal price (LMP) in the PJM Market. For periods prior to the
transfer of the generation business to Power in August 2000, Power Supply
revenues include the sales of energy purchased under the NUG Contracts at LMP.
Any difference between the amounts we pay under the NUG Contracts and the amount
we recover through the NTC and sales at LMP are deferred as a regulatory asset
or liability. The BGS and MTC revenues are offset by a corresponding expense in
Power Supply Costs for the amount paid to Power under the BGS Contract.
The MTC tariff rate decreased 2% in February 2001 effective with the
implementation of securitization in accordance with the BPU's Final Order.
Effective August 1, 2001, we implemented a 2% rate reduction as required by
the Final Order, bringing the total rate decrease to 9% since August 1, 1999.
These rate reductions amounted to approximately $100 million in 2001 and were
funded through the MTC component of rates, which, along with BGS
17
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
revenues, is remitted to Power through Power Supply Costs. An additional
4.9% rate reduction, effective August 1, 2002, will further reduce revenues and
costs.
Generation
Following the transfer of our generation business to Power in August
2000, we no longer record Generation revenues. These revenues, which
reflected generation sold to regulated utility customers and on the wholesale
energy market, were replaced with Power Supply revenues which are offset by
power purchased from Power to meet our BGS obligation.
Gas Distribution
Gas Distribution revenues increased $153 million or 7% in 2001 as
compared to 2000 primarily due to higher gas rates and sales in the appliance
service business. Customer rates in all classes of business have increased in
2001 to recover a portion of the higher natural gas costs. The commercial and
industrial classes fuel recovery rates vary monthly according to the market
price of gas. The BPU also approved increases in the fuel component of the
residential class rates of 16% in November 2000 and 2% for each month from
December 2000 through July 2001. These increased revenues were offset by
higher gas distribution costs, discussed below, and lower sales volumes in
the fourth quarter of 2001 than the comparable period in 2000, primarily
resulting from warmer weather.
Trading
Together with the transfer of our generation business to Power, we
transferred our trading operations to Power in August 2000 and therefore no
longer have Trading revenues.
Operating Expenses
Power Supply
Power Supply costs increased approximately $1.2 billion in 2001 as
compared to 2000 primarily due to the generation asset transfer to Power in
August 2000. These costs represent the amount paid to Power under the BGS
Contract. These amounts also include purchases of energy under various NUG
contracts. Prior to August 2000, the Power Supply costs represented only
purchases of energy under various NUG contracts as we operated our own
generation business. The BGS and MTC costs paid to Power reflect the rate
reductions discussed above.
Gas Costs
Gas Costs increased $167 million or 12% in 2001 as compared to 2000
primarily due to higher natural gas costs. The increase was partially offset by
lower natural gas purchases due to lower sales volumes resulting from comparably
warmer weather in the fourth quarter of 2001 as compared to the same period in
2000. Due to the LGAC, gas costs are increased or decreased to offset a
corresponding increase or decrease in fuel revenues with no impact on income.
Generation Costs
Following the transfer of our generation business to Power in August
2000, we no longer record Generation Costs, which were primarily comprised of
fuel used to generate electricity. These costs were replaced with Power
Supply Costs which include the power purchased to meet our BGS obligation.
Trading Costs
Together with the transfer of our generation business to Power, we
transferred our trading operations to Power in August 2000 and therefore no
longer have Trading Costs.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Operations and Maintenance
Operations and Maintenance expense decreased $286 million or 23% in 2001
as compared to 2000 primarily due to the elimination of $328 million in
Operations and Maintenance expenses resulting from the transfer of the
generation business to Power in August 2000. The decrease was partially offset
by the deferral of costs incurred during 2000 in connection with deregulation
that we expect to recover in future rates.
Depreciation and Amortization
Depreciation and Amortization expense increased $93 million or 32% in
2001 as compared to 2000 primarily due to approximately $180 million of
amortization of the regulatory asset recorded for our stranded costs, which
commenced with the issuance of the transition bonds on January 31, 2001. This
increase was partially offset by the elimination of $77 million of
Depreciation and Amortization expense resulting from the transfer of the
generation business to Power in August 2000.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes decreased $29 million or 18% in 2001 as
compared to 2000. This decrease was partially due to a reduction in net
taxable sales subject to the Transition Energy Facility Assessment (TEFA) tax
and the phaseout of the TEFA. The TEFA was enacted as part of energy tax
reform and was scheduled to be phased out by 2003. Recent legislation delayed
the phase-out until 2007.
Interest Expense
Net Interest Expense increased $102 million or 41% in 2001 as compared to
2000 primarily due to interest of approximately $148 million on the bonds issued
by Transition Funding on January 31, 2001, discussed below, combined with
approximately $78 million lower interest earned in 2001, as compared to 2000.
The reduction in interest earned in 2001 resulted from the repayment of
intercompany loans by PSEG and Power in April 2001 relating to the transfer of
the generation business. These increases were partially offset by $118 million
in lower interest resulting from reduced short-term and long-term debt.
Preferred Securities Dividends
Preferred Securities Dividends decreased $22 million or 48% in 2001 as
compared to 2000 primarily due to the redemption of $240 million and $208
million of preferred securities in March 2001 and June 2001.
Income Taxes
Income taxes decreased $318 million or 78% in 2001 as compared to 2000.
These decreases were primarily due to lower pre-tax operating income due to the
transfer of the generation business to Power in August of 2000. In addition,
taxes decreased due to normal adjustments as a result of closing the 1994-96 IRS
audit and upon filing the actual tax return for the year 2000.
For the Year Ended December 31, 2000 compared to the Year Ended December 31,
1999
Operating Revenues
For the purpose of this discussion, bundled revenues recorded through
July 31, 1999 have been allocated by unbundling the generation component of
revenue from our bundled rate for the generation, transmission and
distribution of energy and adding any other generation-related revenues, such
as ancillary services. The resulting revenue amounts are as follows:
19
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
2000 1999
-------------------- -------------------
(Millions of Dollars)
Electric Transmission and Distribution $1,447 $1,352
Power Supply 1,141 127
Generation 1,110 2,602
-------------------- -------------------
Total Operating Electric Revenues $3,698 $4,081
==================== ===================
Electric Transmission and Distribution
Electric Transmission and Distribution revenues increased $95 million or
7% in 2000 as compared to 1999 primarily due to more favorable weather in
2000.
Power Supply
Power Supply revenues increased approximately $1 billion in 2000 as
compared to 1999 primarily due to the generation asset transfer to Power in
August 2000. Following the transfer, these revenues represent the BGS and MTC
tariff rates charged by us to our customers who are not served by another
supplier, which were approximately $830 million. In addition, following the
unbundling of rates in August 1999, Power Supply revenues include the amount
charged by us to our customers through NTC rates to recover the above market
costs related to energy purchased by us under various NUG Contracts. Power
Supply revenues in 2000 also include sales to Power of energy purchased under
the NUG contracts. These sales are made to Power at the LMP in the PJM Market.
For periods subsequent to the unbundling of rates and prior to the transfer of
the generation business to Power in August 2000, Power Supply revenues also
include the sales of energy purchased under the NUG Contracts at LMP. Any
difference between the amounts we pay under the NUG Contracts and the amount
we recover through the NTC and sales at LMP, are deferred as a regulatory
asset or liability. The BGS and MTC revenues are offset by a corresponding
expense in Power Supply Costs for the amount paid to Power under the BGS
Contract.
Generation
Generation revenues decreased approximately $1.5 billion in 2000 as
compared to 1999 primarily due to the transfer of our generation business to
Power in August 2000. These revenues were replaced with Power Supply revenues,
which are offset by power purchased from Power to meet our BGS obligation.
Also contributing to the decrease was the implementation of a 5% rate
reduction on August 1, 1999 which decreased revenues by approximately $100
million, a $76 million pre-tax charge to income related to MTC recovery in the
third quarter of 2000 and a reduction in revenues resulting from customer
migration. However, the reduction in revenues resulting from customer
migration was substantially offset by higher interchanged sales.
Gas Distribution
Gas Distribution revenues increased $423 million or 25% in 2000 as
compared to 1999 primarily due to increases in natural gas prices being passed
along to customers under certain transportation only contracts. Under these
contracts, we are responsible only for delivery of gas to these customers.
Such customers are responsible for payment to us for the cost of the commodity
and as our costs for these customers increase, the customers rates will
increase. Also contributing to this increase were higher sales resulting from
colder weather in the fourth quarter of 2000 as compared to the same period in
1999 and higher rates approved by the BPU to allow us to recover increasing
natural gas costs.
Trading
Trading revenues decreased $321 million or 17% in 2000 as compared to
1999 primarily due to the transfer of our trading operations to ER&T,
effective August 1, 2000.
20
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Operating Expenses
Power Supply
Power Supply costs increased approximately $1 billion in 2000 as compared
to 1999. For 2000, following the transfer of the generation business to Power,
these costs represent the amount paid to Power under the BGS Contract. These
amounts also include purchases of energy under various NUG contracts. Prior to
August 2000, the Power Supply costs represented only purchases of energy under
various NUG contracts as we operated our own generation business. The BGS and
MTC costs paid to Power reflect the rate reductions discussed above.
Gas Costs
Gas Costs increased $391 million or 38% in 2000 as compared to 1999
primarily due to higher natural gas costs. Due to the Levelized Gas Adjustment
Clause, gas costs are increased or decreased to offset a corresponding
increase or decrease in fuel revenues with no impact on income.
Generation Costs
Generation costs decreased by $450 million or 58% in 2000 as compared to
1999 primarily due to the transfer of the generation business to Power in
August 2000. These costs were replaced with Power Supply costs, discussed
above.
Trading Costs
Trading Costs decreased $328 million or 18% in 2000 as compared to 1999
primarily due to the transfer of our trading operations to ER&T, effective
August 1, 2000.
Operations and Maintenance
Operations and Maintenance expense decreased $312 million or 20% in 2000
as compared to 1999 primarily due to the elimination of Operations and
Maintenance expenses resulting from the transfer of our generation business to
Power in August 2000.
Depreciation and Amortization
Depreciation and Amortization expense decreased $238 million or 45% in
2000 as compared to 1999 primarily due to an impairment write-down of
generation related asset balances recorded as of April 1, 1999, pursuant to
Statement of Financial Accounting Standards (SFAS) No. 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of"
(SFAS 121). The balance of the decrease is due to the elimination of
Depreciation and Amortization expense resulting from the transfer of the
generation business to Power in August 2000.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes include the Transitional Energy Facility
Assessment (TEFA). Taxes Other Than Income Taxes decreased $28 million or 14%
in 2000 as compared to 1999. This decrease was partially due to New Jersey
energy tax reform and the five-year phase out of the TEFA commencing in
January 1999. Effective January 1, 2000, revised rates became effective which
reflected two years phase out of the TEFA. The balance of the decrease is
primarily due to the transfer of our generation business to Power in August
2000.
Interest Expense
Net Interest Expense decreased $133 million or 34% in 2000 as compared to
1999 primarily due to approximately $150 million of interest earned from Power
relating to the intercompany loans for the generation business transfer in
August 2000, partially offset by increased short-term debt outstanding in
anticipation of the securitization financing.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Income Taxes
Income taxes decreased $103 million or 20% in 2000 as compared to 1999
primarily due to lower pre-tax income, due to the transfer of the generation
business to Power in August 2000, coupled with lower effective tax rates
relating to the amortization of the excess depreciation reserve for electric
distribution.
LIQUIDITY AND CAPITAL RESOURCES
All of our publicly traded debt has received investment grade ratings
from each of the three major credit rating agencies. The changes in the energy
industry and the recent bankruptcy of Enron Corp. are attracting increased
attention from the rating agencies, which regularly assess business and
financial matters. Given the changes in the industry, attention to and
scrutiny of our performance, capital structure and competitive strategies by
rating agencies will likely continue. These changes could affect the bond
ratings, cost of capital and market prices of our securities. We will continue
to evaluate our capital structure, financing requirements, competitive
strategies and future capital expenditures to maintain our current credit
ratings.
The current ratings of our securities are shown below and reflect the
respective views of the rating agencies, from whom an explanation of the
significance of their ratings may be obtained. There is no assurance that
these ratings will continue for any given period of time or that they will not
be revised or withdrawn entirely by the rating agencies, if, in their
respective judgments, circumstances so warrant. Any downward revision or
withdrawal may adversely effect the market price of our securities and serve
to increase our cost of capital.
Moody's Standard & Poor's Fitch
--------------------------------------------------------------------------------------------
Mortgage Bonds A3 A- A
Preferred Securities Baa1 BBB A-
Commercial Paper P2 A2 F1
External financing may consist of public and private capital market debt
and equity transactions, bank revolving credit and term loan facilities and/or
commercial paper. Some of these transactions involve special purpose entities.
These are corporations, limited liability companies or partnerships formed in
accordance with applicable tax, accounting and legal requirements in order to
achieve specified beneficial financial advantages, such as favorable tax,
legal liability or accounting treatment. All such special purpose entities
utilized by us and our subsidiaries have been consolidated in our financial
reporting.
The availability and cost of external capital could be affected by our
performance as well as by the performance of our affiliates. This could
include the degree of structural or regulatory separation between us and our
non-utility affiliates and the potential impact of affiliate ratings on credit
quality. Additionally, compliance with applicable financial covenants will
depend upon future financial position and levels of earnings and net cash
flows, as to which no assurances can be given.
Our credit agreements contain cross-default provisions under which a
default by us involving specified levels of indebtedness in other agreements
would result in a default and the potential acceleration of payment under such
credit agreements.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
In addition, our credit agreements generally contain provisions under which
the lenders could refuse to advance loans in the event of a material adverse
change in our business or financial condition. In the event that we or the
lenders in any of our credit agreements determine that a material adverse change
has occurred, loan funds may not be advanced. Such lenders, or the debt holders
under any of our indentures, could determine that debt payment obligations may
be accelerated as a result of a cross-default. These occurrences could severely
limit our liquidity and restrict our ability to meet our debt, capital and, in
extreme cases, operational cash requirements. Any inability to satisfy required
covenants and/or borrowing conditions would have a similar impact. This would
have a material adverse effect on our financial condition, results of operations
and net cash flows, and those of our subsidiaries.
Our debt indentures and credit agreements do not contain any "ratings
triggers" that would cause an acceleration of the required interest and
principal payments in the event of a ratings downgrade. However, in the event
of a downgrade we may be subject to increased interest costs on certain bank
debt.
Capital resources and investment requirements could be affected by the
outcome of proceedings by the BPU pursuant to its Energy Master Plan and
Energy Competition Act and the requirements of the 1992 Focused Audit
conducted by the BPU, of the impact of PSEG's non-utility businesses, owned by
PSEG Energy Holdings (Energy Holdings), on us. As a result of the Focused
Audit, the BPU ordered that, among other things:
(1) PSEG will not permit Energy Holdings' investments to exceed 20% of our
consolidated assets without prior notice to the BPU;
(2) Our Board of Directors would provide an annual certification that the
business and financing plans of Energy Holdings will not adversely
affect us;
(3) PSEG will (a) limit debt supported by the minimum net worth maintenance
agreement between PSEG and PSEG Capital to $650 million and (b) make a
good-faith effort to eliminate such support over a six to ten year
period from May 1993; and
(4) Energy Holdings will pay us an affiliation fee of up to $2 million a
year, which is to be used to reduce customer rates.
In the Final Order the BPU noted that, due to significant changes in the
industry and, in particular, our corporate structure as a result of the Final
Order, modifications to or relief from the Focused Audit order might be
warranted. We have notified the BPU that PSEG will eliminate PSEG Capital debt
by the second quarter of 2003 and that we believe that the Final Order otherwise
supercedes the requirements of the Focused Audit. While we believe that this
issue will be satisfactorily resolved, no assurances can be given.
In addition, if PSEG were no longer to be exempt under the Public Utility
Holding Company Act of 1935 (PUHCA), we would be subject to additional
regulation by the SEC with respect to financing and investing activities. We
believe that this would not have a material adverse effect on our financial
condition, results of operations and net cash flows.
Over the next several years, we will be required to refinance maturing
debt, incur additional debt and retain earnings to fund investment activity. Any
inability to obtain required additional external capital or to extend or replace
maturing debt and/or existing agreements at current levels and reasonable
interest rates may affect our financial condition, results of operations and net
cash flows.
In March 2001, we reduced the maximum size of our commercial paper program
from $1.5 billion to $900 million. Effective March 8, 2002, this amount will be
further reduced to $550 million. To provide liquidity for this program, we have
three revolving credit facilities with a group of banks totaling $900 million
($550 million effective March 8, 2002), each of which expires in June 2002. In
addition, we have an uncommitted line of credit with a bank. As of December 31,
2001, we had no short-term debt outstanding.
Under our Mortgage, we may issue new First and Refunding Mortgage Bonds
against previous additions and improvements and/or retired Mortgage Bonds
provided that our ratio of earnings to fixed charges calculated in
23
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
accordance with our Mortgage is at least 2:1. At December 31, 2001, our
Mortgage coverage ratio was 3:1. As of December 31, 2001, the Mortgage would
permit up to approximately $1 billion aggregate principal amount of new Mortgage
Bonds to be issued against previous additions and improvements. We will need to
obtain BPU authorization to issue any incremental debt financing necessary for
our capital program including refunds of maturing debt and opportunistic
refinancing. In January 2002, we filed a petition with the BPU for authorization
to issue $1 billion of long-term debt through December 31, 2003.
In December 2001, we filed a shelf registration statement on Form S-3 for
the issuance of $1 billion of debt and tax deferred preferred securities, which
was declared effective by the SEC in February 2002.
In January 2001, $2.525 billion of transition bonds were issued by
Transition Funding in eight classes with maturities ranging from 1 year to 15
years. We also received payment from Power on its $2.786 billion promissory note
used to finance the transfer of our generation business to Power. The proceeds
from these transactions were used to pay for certain debt issuance and related
costs for securitization, retire a portion of our outstanding short-term debt,
reduce our common equity, loan funds to PSEG and make various short-term
investments.
In March 2001, we redeemed all of our $150 million of 9.375% Series A
cumulative monthly income preferred securities, all of our $75 million of
5.97% preferred stock, $15 million of our 6.75% preferred stock and $52
million of our floating rate notes due December 7, 2002. In June 2001, we
redeemed the remaining $248 million outstanding of floating rate notes due
December 7, 2002.
In June 2001, we redeemed all of our $208 million of 8.625% Series A
cumulative quarterly income preferred securities.
In November 2001, $100 million of our Mortgage Bonds, Series FF matured.
Also in November 2001, we redeemed $105 million of our variable rate Pollution
Control Notes. In December 2001, we redeemed an additional $19 million of our
variable rate Pollution Control Notes.
Since 1986, we have made regular cash payments to PSEG in the form of
dividends on outstanding shares of our common stock. We paid common stock
dividends of $112 million and $638 million to PSEG for the years ended
December 31, 2001 and 2000, respectively.
We have issued Deferrable Interest Subordinated Debentures in connection
with the issuance of tax deductible preferred securities. If payments on those
Deferrable Interest Subordinated Debentures are deferred, in accordance with
their terms, we may not pay any dividends on our common or preferred stock
until such default is cured. Currently, there has been no deferral or default.
CAPITAL REQUIREMENTS
Forecasted Expenditures
We have substantial commitments as part of our ongoing construction
programs. We expect that the majority of our capital requirements over the
next five years will come from internally generated funds, with the balance to
be provided by the issuance of debt and equity contributions from PSEG.
For the year ended December 31, 2001, we made net plant additions of
$398 million, excluding Allowance for Funds Used During Construction (AFDC)
related to improvements in our transmission and distribution system, gas
system and common facilities. Our projected construction expenditures for the
next five years range from $440 million to $485 million per year.
24
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Our construction expenditures are primarily to maintain the safety and
reliability of our electric and gas transmission and distribution facilities.
Our ongoing construction programs are continuously reviewed and periodically
revised as a result of changes in economic conditions, revised load forecasts,
business strategies, site changes, cost escalations under construction
contracts, requirements of regulatory authorities and laws, the timing of and
amount of electric and gas transmission and/or distribution rate changes and
our ability of us to raise necessary capital.
Disclosures about Contractual Obligations
The following tables, reflect our contractual cash obligations in the
respective periods in which they are due.
Less
Total Amounts Than
Contractual Cash Obligations Committed 1 year 2 - 3 years 4 - 5 years Over 5 years
(Millions of Dollars)
------------------------------------------------------------------------------
Long - Term Debt $5,645 $547 $638 $272 $4,188
Capital Lease Obligations 102 8 16 16 62
Operating Leases 13 3 5 4 1
------------------------------------------------------------------------------
Total Contractual Cash Obligations $5,760 $558 $659 $292 $4,251
==============================================================================
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT
MARKET RISK
The market risk inherent in our market risk sensitive instruments and
positions is the potential loss arising from adverse changes in commodity
prices and interest rates as discussed in the Notes to Consolidated Financial
Statements. Our policy is to use derivatives to manage risk consistent with
our business plans and prudent practices. PSEG has a Risk Management Committee
comprised of executive officers, which we utilize for an independent risk
oversight function to ensure compliance with corporate policies and prudent
risk management practices.
We are exposed to credit losses in the event of non-performance or
non-payment by counterparties. We also have a credit management process, which
is used to assess, monitor and mitigate our counterparty exposure. In the
event of non-performance or non-payment by a major counterparty, there may be
a material adverse impact on our financial condition, results of operations or
net cash flows.
We use natural gas futures and swaps to reduce exposure to price
fluctuations from factors such as weather, changes in demand and changes in
supply to manage the price risk associated with gas supply to our customers.
These instruments, in conjunction with physical gas supply contracts, are
designed to cover estimated gas customer commitments. We have entered into 330
MMBTU of gas futures, swaps and options to hedge forecasted requirements. As of
December 31, 2001, the fair value of those instruments was $(137) million with a
maximum term of approximately one year. We utilize derivatives to hedge our gas
purchasing activities which, when realized, are recoverable through our LGAC.
Accordingly, the offset to the change in fair value of these derivatives is
recorded as a regulatory asset or liability.
As a result of the gas contract transfer that is anticipated to take
place in April 2002, our price risk relating to gas purchases will be
transferred to Power. As a result, after that date, we will not be utilizing
these derivative instruments in our gas distribution business.
Through the BGS auction, we have contracted for our expected peak load of
9,600 MW. If our peak load should exceed this amount or one of our suppliers
defaults on their contract, we may have to purchase power on the open market
and use commodity contracts during periods of high demand. To the extent that
the market prices exceed the
25
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
auction contract price, the difference will be deferred and collected from our
customers as provided in the BPU Order approving the auction process.
Given the absence of a PJM price cap in situations involving emergency
purchases and the potential for plant outages, extreme price movements can
occur and could have a material impact on our financial condition and net cash
flows.
We are subject to the risk of fluctuating interest rates in the normal
course of business. Our policy is to manage interest rate risk through the use
of fixed rate debt, floating rate debt and interest rate swaps. As of December
31, 2001, a hypothetical 10% change in market interest rates would result in a
$4 million change in annual interest costs related to our short-term and
floating rate debt.
Transition Funding has entered into an interest rate swap on its sole
class of floating rate transition bonds. The notional amount of the interest
rate swap is approximately $497 million. The interest rate swap is indexed to
the three-month LIBOR rate. The fair value of the interest rate swap was
approximately $(18) million as of December 31, 2001 and was recorded as a
derivative liability, with an offsetting amount recorded as a regulatory asset
on the Consolidated Balance Sheet. This amount will vary over time as a result
of changes in market conditions.
ACCOUNTING ISSUES
Critical Accounting Policies and Other Accounting Matters
Our most critical accounting policies include the application of: SFAS No.
71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) for our
regulated transmission and distribution business and SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities", as amended (SFAS 133), to
account for our various hedging transactions.
Accounting for the Effects of Regulation
We prepare our financial statements in accordance with the provisions of
SFAS No. 71, which differs in certain respects from the application of
Generally Accepted Accounting Principles (GAAP) by non-regulated businesses.
In general, SFAS 71 recognizes that accounting for rate-regulated enterprises
should reflect the economic effects of regulation. As a result, a regulated
entity is required to defer the recognition of costs (a regulatory asset) or
the recognition of obligations (a regulatory liability) if it is probable
that, through the rate-making process, there will be a corresponding increase
or decrease in future rates. Accordingly, we have deferred certain costs,
which will be amortized over various future 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 our competitive position, the
associated regulatory asset or liability is charged or credited to income.
As a result of New Jersey deregulation legislation and regulatory orders
issued by the BPU, certain regulatory assets and liabilities were recorded.
The amortization of two of these regulatory liabilities will have a
significant effect on our annual earnings. They include the estimated amount
of MTC revenues to be collected in excess of the authorized amount of $540
million and the amount of excess electric distribution depreciation reserves.
The amount of these regulatory liabilities will be amortized to earnings over
the four-year transition period from August 1, 1999 through July 31, 2003.
The MTC was authorized by the BPU as an opportunity to recover up to $540
million (net of tax) of our unsecuritized generation-related stranded costs on
a net present value basis. As a result of the appellate reviews of the Final
Order, our securitization transaction was delayed until the first quarter of
2001, causing a delay in the implementation of the Securitization Transition
Charge (STC), which would have reduced the MTC. As a result, MTC was being
recovered at a faster rate than intended under the Final Order and a
significant overrecovery was
26
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
probable. In order to properly recognize the recovery of the allowed
unsecuritized stranded costs over the transition period, we recorded a
regulatory liability and a charge to net income of $76 million, pre-tax, or
$45 million, after tax, in the third quarter of 2000 for the cumulative
amount of estimated collections in excess of the allowed unsecuritized
stranded costs for the period prior to the generation-related asset transfer
to Power. We then began deferring a portion of these revenues each month to
recognize the estimated collections in excess of the allowed unsecuritized
stranded costs. As of December 31, 2001, this deferred amount was $168
million and is aggregated with the Societal Benefits Clause.
The amortization of the Excess Electric Distribution Depreciation Reserve
is another significant regulatory liability affecting our earnings. As required
by the BPU, we reduced our depreciation reserve for our electric distribution
assets by $569 million and recorded such amount as a regulatory liability to be
amortized over the period from January 1, 2000 to July 31, 2003. In 2000 and
2001, $125 million was amortized and recorded as a reduction of depreciation
expense pursuant to the Final Order. The remaining $319 million will be
amortized through July 31, 2003.
See Note 4. Regulatory Assets and Liabilities for further discussion of
these and other regulatory issues.
SFAS 133 - Accounting for Derivative Instruments and Hedging Activities
SFAS 133 established accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires an entity to recognize the
fair value of derivative instruments held as assets or liabilities on the
balance sheet. In accordance with SFAS 133, the effective portion of the change
in the fair value of a derivative instrument designated as a cash flow hedge is
reported in other comprehensive income (OCI), net of tax, or as a Regulatory
Asset (Liability). Amounts in accumulated OCI are ultimately recognized in
earnings when the related hedged forecasted transaction occurs. The change in
the fair value of the ineffective portion of the derivative instrument
designated as a cash flow hedge is recorded in earnings. Derivative instruments
that have not been designated as hedges are adjusted to fair value through
earnings. We have entered into several derivative instruments, including
interest rate swaps which have been designated as cash flow hedges. The fair
value of the derivative instruments is determined by reference to quoted market
prices, listed contracts, published quotations or quotations from
counterparties.
For additional information regarding Derivative Financial Instruments,
See Note 7 Financial Instruments and Risk Management.
Other Accounting Issues
For additional information on our accounting policies and the
implementation of recently issued accounting standards, see Note 1.
Organization, Basis of Presentation and Summary of Significant Accounting
Policies and Note 2. Accounting Matters, respectively.
FORWARD LOOKING STATEMENTS
Except for the historical information contained herein, certain of the
matters discussed in this report constitute "forward-looking statements"
within the meaning of the Private Securities Litigation Reform Act of 1995.
Such forward-looking statements are subject to risks and uncertainties, which
could cause actual results to differ materially from those anticipated. Such
statements are based on management's beliefs as well as assumptions made by
and information currently available to management. When used herein, the
words "will", "anticipate", "intend", "estimate", "believe", "expect",
"plan", "hypothetical", "potential", variations of such words and similar
expressions are intended to identify forward-looking statements. We undertake
no obligation to publicly update or revise any
27
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
forward-looking statements, whether as a result of new information, future
events or otherwise. The following review of factors should not be construed
as exhaustive or as any admission regarding the adequacy of our disclosures
prior to the effective date of the Private Securities Litigation Reform Act
of 1995.
In addition to any assumptions and other factors referred to
specifically in connection with such forward-looking statements, factors that
could cause actual results to differ materially from those contemplated in
any forward-looking statements include, among others, the following:
o failure to obtain adequate and timely rate relief may have an
adverse impact;
o deregulation and the unbundling of energy supplies and services and
the establishment of a competitive energy marketplace;
o inability to raise capital on favorable terms to refinance existing
indebtedness or to fund capital commitments;
o changes in the economic and electricity and gas consumption growth
rates;
o environmental regulation may limit our operations;
o insurance coverage may not be sufficient; and
o recession, acts of war or terrorism could have an adverse impact.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES
ABOUT MARKET RISK
Information relating to quantitative and qualitative disclosures about
market risk is set forth under the caption "Qualitative and Quantitative
Disclosures About Market Risk" in Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations. Such information is
incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA
28
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars)
For The Years Ended December 31,
--------------------------------------------------
2001 2000 1999
------------- ------------- -------------
OPERATING REVENUES
Electric Transmission and Distribution $ 1,481 $ 1,447 $ 561
Bundled - - 2,445
Power Supply 2,317 1,141 127
Generation - 1,110 948
Gas Distribution 2,293 2,140 1,717
Trading - 1,521 1,842
------------- ------------- -------------
Total Operating Revenues 6,091 7,359 7,640
------------- ------------- -------------
OPERATING EXPENSES
Power Supply 2,317 1,141 127
Gas Costs 1,596 1,429 1,038
Generation - 331 781
Trading - 1,472 1,800
Operation and Maintenance 975 1,261 1,573
Depreciation and Amortization 384 291 529
Taxes Other Than Income Taxes 137 166 194
------------- ------------- -------------
Total Operating Expenses 5,409 6,091 6,042
------------- ------------- -------------
OPERATING INCOME 682 1,268 1,598
Other Income and Deductions 22 26 (2)
Interest Expense-net (356) (254) (387)
Preferred Securities Dividend Requirements (24) (46) (46)
------------- ------------- -------------
INCOME BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM 324 994 1,163
Income Taxes (89) (407) (510)
------------- ------------- -------------
INCOME BEFORE EXTRAORDINARY ITEM 235 587 653
Extraordinary Item (Net of Tax of $345) - - (804)
------------- ------------- -------------
NET INCOME (LOSS) 235 587 (151)
Preferred Stock Dividend Requirement (5) (9) (9)
------------- ------------- -------------
EARNINGS (LOSS) AVAILABLE TO
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 230 $ 578 $ (160)
============= ============= =============
* Note: Bundled revenues were recorded based on the bundled rates in effect
through July 31, 1999. Commencing with the unbundling of rates on August 1,
1999, revenues are disaggregated between Generation Revenue and
Transmission and Distribution Revenue.
See Notes to Consolidated Financial Statements.
29
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
December 31,
--------------------------------
2001 2000
-------------- --------------
CURRENT ASSETS
Cash and Cash Equivalents $ 102 $ 39
Accounts Receivable:
Customer Accounts Receivable 556 614
Other Accounts Receivable 67 71
Allowance for Doubtful Accounts (38) (39)
Unbilled Revenues 291 357
Fuel 415 372
Materials and Supplies 50 48
Prepayments 40 5
Energy Contracts 32 -
Restricted Cash 13 1
Other 21 23
-------------- --------------
Total Current Assets 1,549 1,491
-------------- --------------
PROPERTY, PLANT AND EQUIPMENT
Electric 5,501 5,302
Gas 3,284 3,177
Other 385 420
-------------- --------------
Total 9,170 8,899
Accumulated depreciation and amortization (3,329) (3,139)
-------------- --------------
Net Property, Plant and Equipment 5,841 5,760
-------------- --------------
NONCURRENT ASSETS
Regulatory Assets 5,220 4,995
Notes Receivable - Affiliated Companies - 2,786
Long-Term Investments 112 109
Other Special Funds 130 70
Other 84 56
-------------- --------------
Total Noncurrent Assets 5,546 8,016
-------------- --------------
TOTAL $ 12,936 $ 15,267
============== ==============
See Notes to Consolidated Financial Statements.
30
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions of Dollars)
December 31,
-------------------------------------
2001 2000
-------------- ------------------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 668 $ 100
Commercial Paper and Loans - 1,543
Accounts Payable 642 748
Energy Contracts 169 -
Other 280 253
-------------- ------------------
Total Current Liabilities 1,759 2,644
-------------- ------------------
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 2,551 2,701
Regulatory Liabilities 373 470
OPEB Costs 466 441
Other 205 223
-------------- ------------------
Total Noncurrent Liabilities 3,595 3,835
-------------- ------------------
COMMITMENTS AND CONTINGENT LIABILITIES - -
-------------- ------------------
CAPITALIZATION:
LONG-TERM DEBT 4,977 3,590
-------------- ------------------
PREFERRED SECURITIES:
Preferred Stock Without Mandatory Redemption 80 95
Preferred Stock With Mandatory Redemption - 75
Subsidiaries' Preferred Securities:
Guaranteed Preferred Beneficial Interest in Subordinated
Debentures 155 513
-------------- ------------------
Total Preferred Securities 235 683
-------------- ------------------
COMMON STOCKHOLDER'S EQUITY:
Common Stock, issued; 132,450,344 shares 892 2,563
Contributed Capital - 594
Basis Adjustment 986 986
Retained Earnings 493 375
Accumulated Other Comprehensive Income (Loss) (1) (3)
-------------- ------------------
Total Common Stockholder's Equity 2,370 4,515
-------------- ------------------
Total Capitalization 7,582 8,788
-------------- ------------------
TOTAL $ 12,936 $ 15,267
============== ==================
See Notes to Consolidated Financial Statements.
31
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
For The Years Ended December 31,
------------------------------------------
2001 2000 1999
----------- ---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 235 $ 587 $ (151)
Adjustments to reconcile net income (loss) to net cash flows from
operating activities:
Extraordinary Loss - net of tax - - 804
Depreciation and Amortization 384 291 529
Amortization of Nuclear Fuel - 36 92
Recovery of Electric Energy and Gas Costs - net (86) 16 61
Excess Unsecuritized Stranded Costs 54 115 -
Provision for Deferred Income Taxes and ITC - net (267) (12) (181)
Net Changes in certain current assets and liabilities:
Accounts Receivable and Unbilled Revenues 127 (298) (198)
Inventory - Fuel and Materials and Supplies (45) (172) 10
Prepayments (35) 27 4
Accounts Payable (106) 294 68
Other Current Assets and Liabilities 152 39 25
Other (2) (26) 87
----------- ---------- ----------
Net Cash Provided By Operating Activities 411 897 1,150
----------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment, excluding AFDC (398) (401) (479)
Contribution to Decommissioning Funds and Other Special Funds (94) (4) (70)
Other (32) (15) (34)
----------- ---------- ----------
Net Cash Used In Investing Activities (524) (420) (583)
----------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt (1,543) 68 625
Issuance of Long-Term Debt 2,525 590 -
Redemption/Purchase of Long-Term Debt (570) (622) (423)
Deferred Issuance Costs (192) - -
Redemption of Preferred Stock (448) - -
Return of Capital (2,265) - -
Collection of Notes Receivable-Affiliated Company 2,786 - -
Cash Dividends Paid on Common Stock (112) (638) (629)
Preferred Stock Dividend Requirements (5) (9) (9)
----------- ---------- ----------
Net Cash Provided By (used In) Financing Activities 176 (611) (436)
----------- ---------- ----------
Net Change In Cash And Cash Equivalents 63 (134) 131
Cash And Cash Equivalents At Beginning Of Period 39 173 42
----------- ---------- ----------
Cash And Cash Equivalents At End Of Period $ 102 $ 39 $ 173
=========== ========== ==========
Income Taxes Paid $ 264 $ 593 $ 537
Interest Paid $ 455 $ 406 $ 409
See Notes to Consolidated Financial Statements.
32
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(Millions of Dollars)
Accumulated
Contributed Other
Common Capital from Basis Retained Comprehensive
Stock PSEG Adjustment Earnings Loss Total
---------- ------------ ---------- -------- -------------- --------
Balance as of January 1, 1999 $ 2,563 $ 594 - $1,386 $ (3) $ 4,540
---------- ------------ ---------- -------- -------------- --------
Net Loss - - - (151) - (151)
Other Comprehensive Income, net of tax: - - - - - -
--------
Comprehensive Loss - - - - - (151)
--------
Cash Dividends on Common Stock - - - (629) - (629)
Cash Dividends on Preferred Stock - - - (9) - (9)
---------- ------------ ---------- -------- -------------- --------
Balance as of December 31, 1999 2,563 594 - 597 (3) 3,751
---------- ------------ ---------- -------- -------------- --------
Net Income - - - 587 - 587
Other Comprehensive Income, net of tax: - - - - - -
--------
Comprehensive Income - - - - - 587
--------
Cash Dividends on Common Stock - - - (800) - (800)
Cash Dividends on Preferred Stock - - - (9) - (9)
Basis Adjustment - - 986 - - 986
---------- ------------ ---------- -------- -------------- --------
Balance as of December 31, 2000 2,563 594 986 375 (3) 4,515
---------- ------------ ---------- -------- -------------- --------
Net Income - - - 235 - 235
Other Comprehensive Income , net of tax: - - - - - -
Pension Adjustments, net of tax $(1) - - - - 2 2
--------
Comprehensive Income - - - - - 237
--------
Cash Dividends on Common Stock - - - (112) - (112)
Cash Dividends on Preferred Stock - - - (5) - (5)
Return of Capital (1,671) (594) - - - (2,265)
Basis Adjustment - - - - - -
---------- ------------ ---------- -------- -------------- --------
Balance as of December 31, 2001 $ 892 $ - $ 986 $ 493 $ (1) $ 2,370
========== ============ ========== ======== ============== ========
See Notes to Consolidated Financial Statements.
33
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization, Basis of Presentation and Summary of Significant
Accounting Policies
Organization
Unless the context otherwise indicates, all references to "PSE&G," "we,"
"us" or "our" herein means Public Service Electric & Gas Company, a New Jersey
corporation with its principal executive offices at 80 Park Plaza, Newark, New
Jersey 07102. We are a wholly-owned subsidiary of Public Service Enterprise
Group Incorporated (PSEG) and are an operating public utility providing electric
and gas service in certain areas within the State of New Jersey. Following the
transfer of our generation-related assets to PSEG Power LLC (Power) in August
2000, we continue to maintain our electric transmission and electric and gas
distribution businesses. PSEG owns all of our common stock. Of the 150,000,000
authorized shares of common stock at December 31, 2001 and 2000, there were
132,450,344 shares outstanding.
Basis of Presentation
Effective August 1, 2000, our presentation of Electric Revenues and Power
Supply Costs in our Consolidated Statements of Income has changed due to the
transfer of our electric generating facilities and wholesale power contracts to
Power. Effective with the transfer, we pay a fixed price for energy and capacity
provided by Power under a contract to meet our basic generation service (BGS)
obligation through July 31, 2002 and charge such costs to our BGS customers. As
a result, we transferred the market risk related to our estimated electric
commitments to Power. On February 4, 2002 the New Jersey Board of Public
Utilities (BPU) held an auction to determine who will supply BGS to New Jersey
Utilities for the one year period subsequent to July 31, 2002, which was
approved on February 15, 2002. Through the auction, we successfully secured
contracts with multiple suppliers for 100% of our expected peak load for the
period.
Effective August 1, 1999, the presentation of revenues in our
Consolidated Statements of Income had changed due to the deregulation of the
electric generation business by the BPU in its Energy Master Plan Proceedings.
Effective with that date, electric rates charged to customers have been
unbundled and the generation, transmission, distribution and other components
of the total rate have become separate charges to our customers. Revenues
earned prior to August 1, 1999 continue to be presented as Bundled Electric
Revenues on our Consolidated Statements of Income as they were earned based
upon bundled electric rates effective for that period.
Summary of Significant Accounting Policies
Consolidation
The Consolidated Financial Statements include our accounts and those of
PSE&G Transition Funding LLC (Transition Funding) and our other subsidiaries. We
consolidate those entities in which we have a controlling interest. All
significant intercompany accounts and transactions are eliminated in
consolidation.
Regulation
We prepare our financial statements in accordance with the provisions of
Statement of Financial Accounting Standards (SFAS) 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
economic effects of regulation. As a result, a regulated utility is required
to defer the recognition of costs (a regulatory asset) or the recognition of
revenues (a regulatory liability) if it is probable that, through the
ratemaking process, there will be a corresponding increase or decrease in
future rates. Accordingly, we have deferred certain costs and revenues, which
will be
34
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
amortized over various future 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 our competitive position, the associated regulatory
asset or liability is charged or credited to income. Our transmission and
distribution business continues to meet the requirements for application SFAS
71.
Revenues and Fuel Costs
Electric and gas revenues are recorded based on services rendered to
customers during each accounting period. We record unbilled revenues for 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.
Prior to August 1, 1999, fuel revenue and expense flowed through the
Electric Levelized Energy Adjustment Clause (LEAC) mechanism. Variances in fuel
revenues and expenses were subject to deferral accounting and had no direct
effect on earnings. Under the LEAC and the Levelized Gas Adjustment Clause (L
GAC), any LEAC and LGAC underrecoveries 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. Pursuant to a BPU
Order, the fuel component of the LEAC rate was frozen for 1997 and 1998 and we
bore all risks associated with fuel prices. Following the transfer of
generation-related assets and liabilities in August 2000, we no longer bear the
risks and rewards of changes in nuclear and fossil generating fuel costs and
replacement power costs.
Power Supply Revenues and Costs
Power Supply revenues since August 1, 2000 represent the Basic Generation
Service (BGS) and Market Transition Charge (MTC) tariff rates charged by us to
our customers who are not served by another supplier and Non-Utility
Generation Transition Charge (NTC) rates charged by us to our customers to
recover the above market costs related to energy purchased by us under various
Non-Utility Generation (NUG) Contracts. Power Supply revenues in 2001 also
include sales to Power of energy purchased under the NUG Contracts. These
sales are made to Power at the Locational Marginal Price (LMP) in the
Pennsylvania-New Jersey Maryland Power Pool (PJM) Market. For periods prior to
the transfer of the generation business to Power in August 2000, Power Supply
revenues include the sales of energy purchased under the NUG contracts at LMP.
Any difference between the amounts we pay under the NUG Contracts and the
amount we recover through the NTC and sales at LMP are deferred as a
regulatory asset or liability. The BGS and MTC revenues are offset by a
corresponding expense in Power Supply Costs for the amount paid to Power under
our contract with Power pursuant to which Power delivers energy and capacity
to us under our full requirements contract (BGS Contract). The costs of energy
purchased under the NUG contracts are also included in Power Supply Costs.
Cash and Cash Equivalents
The December 31, 2001 and 2000 balances consist primarily of cash, working
funds and highly liquid marketable securities (commercial paper and money market
funds) with an original maturity of three months or less.
Restricted Cash
Transition Funding has deposited funds with a Trustee which are required to
be used for payment of principal, interest and other expenses related to its
transition bonds (see Note 3. Regulatory Issues and Accounting Impacts of
Deregulation). Accordingly, these funds are classified as "Restricted Cash" on
our Consolidated Balance Sheets.
Fuel and Materials and Supplies
Our fuel and materials and supplies are carried on the books at average
cost in accordance with rate-based regulation.
35
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Depreciation and Amortization
We calculate depreciation under the straight-line method 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. The depreciation rate stated in a
percentage of original cost of depreciable property was 3.32% for 2001 and
3.52% for 2000 and 1999. We have certain regulatory assets and liabilities
resulting from the use of a level of depreciation expense in the ratemaking
process that differs from the amount that is recorded under GAAP for
non-regulated companies.
Unamortized Loss on Reacquired Debt and Debt Expense
Bond issuance costs and associated premiums and discounts are generally
amortized over the life of the debt issuance. In accordance with Federal
Energy Regulatory Commission (FERC) regulations, our costs to reacquire debt
are deferred and amortized over the remaining original life of the retired
debt. When refinancing debt, the unamortized portion of the original debt
issuance costs of the debt being retired must be amortized over the life of
the replacement debt. Gains and losses on reacquired debt are deferred and
amortized to interest expense over the period approved for ratemaking
purposes.
Allowance for Funds Used During Construction (AFDC)
AFDC represents the cost of debt and equity funds used to finance the
construction of 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
(if any). The rates used for calculating AFDC in 2001, 2000 and 1999 were 6.71%,
6.45%, and 5.29%, respectively. In 2001, 2000 and 1999, AFDC amounted to $2
million, $1 million and $3 million, respectively.
Income Taxes
We file a consolidated Federal income tax return with PSEG and income
taxes are allocated to us and each of PSEG's other subsidiaries based on the
taxable income or loss of each respective subsidiary. Investment tax credits
were deferred in prior years and are being amortized over the useful lives of
the related property.
Property, Plant and Equipment
Our additions to property, plant and equipment and replacements that are
either retirement units or property record units are capitalized at original
cost. The cost of maintenance, repair and replacement of minor items of
property is charged to appropriate expense accounts. At the time units of
depreciable property are retired or otherwise disposed, the original cost less
net salvage value is charged to accumulated depreciation.
Commodity Contracts
Effective January 1, 1999 through the transfer of the energy trading
business to Power in August 2000, we utilized Emerging Issues Task Force (EITF)
Issue 98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" (EITF 98-10). EITF 98-10 requires that energy trading
contracts not utilized to hedge price risk be marked to market with gains and
losses included in current earnings.
We engage in natural gas commodity forwards, futures, swaps and options
purchases and sales with counterparties to manage exposure to natural gas price
risk associated with fluctuations from factors such as weather, changes in
demand and changes in supply. These
36
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
instruments, in conjunction with physical gas supply contracts, are designed to
cover estimated gas customer commitments. In accordance with SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS
133), such energy contracts are recognized at fair value as derivative assets or
liabilities on the balance sheet. These derivatives, when realized, are
recoverable through the LGAC. Accordingly, the offset to the change in fair
value of these derivatives is specified as a regulatory asset or liability.
In July 2000, EITF 99-19, "Reporting Revenue Gross as a Principal versus
Net as an Agent" (EITF 99-19), provided guidance on the issue of whether a
company should report revenue based on the gross amount billed to the customer
or the net amount retained. The guidance states that whether a company should
recognize revenue based on the gross amount billed or the net retained requires
significant judgment, which depends on the relevant facts and circumstances.
Based on the analysis and interpretation of EITF 99-19, we report all of the
energy trading revenues and energy trading-related costs on a gross basis for
physical bilateral energy and capacity sales and purchases. We continue to
report swaps, futures, option premiums, firm transmission rights, transmission
congestion credits, and purchases and sales of emission allowances on a net
basis. The prior year financial statements have been reclassified accordingly.
For additional information regarding commodity-related contracts, See Note 7 -
Financial Instruments and Risk Management.
Capital Leases as Lessee
The Consolidated Balance Sheets include assets and related obligations
applicable to capital leases under which the entity is a lessee. Our capital
leases primarily relate to our corporate headquarters. 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. See Note
8. Commitments and Contingent Liabilities.
Impairment of Long-Lived Assets
We review long-lived assets for possible impairment whenever events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Upon deregulation, we evaluated the recoverability of our assets
and recorded an extraordinary, non-cash charge to earnings. For the impact of
the application of SFAS No. 121 "Accounting for the Impairment of Long-Lived
Assets and Long-Lived Assets to Be Disposed Of" (SFAS 121), see Note 3.
Regulatory Issues and Accounting Impacts of Deregulation.
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.
Reclassifications
Certain reclassifications of amounts reported in prior periods have been
made to conform with the current presentation.
Note 2. Accounting Matters
In July 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS
141). SFAS 141 was effective July 1, 2001 and requires that all business
combinations on or after that date be accounted for under the purchase
37
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
method. Upon implementation of this standard, there was no impact on our
financial position or results of operations and we do not believe it will
have a substantial effect on our strategy.
Also, in July 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is considered a
nonamortizable asset and will be subject to an annual review for impairment
and an interim review when required by events or circumstances. SFAS 142 is
effective for all fiscal years beginning after December 15, 2001. We do not
have any goodwill or other intangible assets on our balance sheet. Therefore,
there will be no effect on our financial position or results of operations as
a result of adopting this standard.
Also in July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS 143). Upon adoption of SFAS 143, the fair value
of a liability for an asset retirement obligation is required to be recorded.
Upon settlement of the liability, an entity either settles the obligation for
its recorded amount or incurs a gain or loss upon settlement. SFAS 143 is
effective for fiscal years beginning after June 15, 2002. We are currently
evaluating the effect of this guidance and cannot predict the impact on our
financial position or results of operations; however, such impact could be
material.
In August 2001, the FASB issued SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets" (SFAS 144). Under SFAS 144, long-lived assets to
be disposed of should be measured at the lower of carrying amount or fair value
less cost to sell, whether reported in continued operations or in discontinued
operations. Discontinued operations will no longer be measured at net realizable
value or include amounts for operating losses that have not yet occurred. The
statement also broadens the reporting of discontinued operations. SFAS 144 is
effective for fiscal years beginning after December 15, 2001. We are currently
evaluating this guidance and do not believe that it will have a material impact
on our financial position or results of operations.
Note 3. Regulatory Issues and Accounting Impacts of Deregulation
New Jersey Energy Master Plan Proceedings and Related Orders
Following the enactment of the New Jersey Electric Discount and Energy
Competition Act, the BPU rendered a Final Order relating to our rate
unbundling, stranded costs and restructuring proceedings (Final Order).
Pursuant to the Final Order, we transferred our electric generating facilities
and wholesale power contracts to Power and its subsidiaries on August 21, 2000
in exchange for a promissory note in an amount equal to the purchase price.
The generating assets were transferred at the price specified in the BPU
order - $2.443 billion plus $343 million for other generation related assets and
liabilities. Because the transfer was between affiliates, we recorded the sale
at the net book value of the assets and liabilities rather than the transfer
price. The difference between the total transfer price and the net book value of
the generation-related assets and liabilities was recorded as an equity
adjustment on Power's and our Consolidated Balance Sheets. These amounts are
eliminated on PSEG's consolidated financial statements. Power paid the
promissory note on January 31, 2001.
Also in the Final Order, the BPU concluded that we should recover up to
$2.94 billion (net of tax) of our generation-related stranded costs through
securitization of $2.4 billion and an opportunity to recover up to $540
million (net of tax) of our unsecuritized generation-related stranded costs on
a net present value basis. The $540 million is subject to recovery through a
market transition charge (MTC). We remit the MTC revenues to Power as part of
the BGS contract as provided for by the Final Order.
In September 1999, the BPU issued its order approving our petition
relating to the proposed securitization transaction (Finance Order) which
authorized, among other things, the imposition of a non-bypassable transition
38
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
bond charge (TBC) on our customers; the sale of our property right in such
charge to a bankruptcy-remote financing entity; the issuance and sale of
$2.525 billion of transition bonds by such entity as consideration for such
property right, including an estimated $125 million of transaction costs; and
our application of the transition bond proceeds to retire outstanding debt
and/or equity. Transition Funding issued the transition bonds on January 31,
2001 and the TBC and a 2% rate reduction became effective on February 7, 2001 in
accordance with the Final Order. An additional 2% rate reduction became
effective on August 1, 2001 bringing the total rate reduction to 9% since
August 1, 1999. These rate reductions and the TBC were funded through the MTC
rate.
On January 31, 2001, $2.525 billion of transition bonds (non-recourse
asset backed securities) were issued by Transition Funding, in eight classes
with maturities ranging from 1 year to 15 years. Also on January 31, 2001, we
received payment from Power on the $2.786 billion promissory note used to
finance the transfer of our generation business. The proceeds from these
transactions were used to pay for certain debt issuance and related costs for
securitization, retire a portion of our outstanding short-term debt, reduce
our common equity, loan funds to PSEG and make various short-term investments.
Extraordinary Charge and Other Accounting Impacts of Deregulation
In April 1999, we determined that SFAS 71 was no longer applicable to the
electric generation portion of our business in accordance with the requirements
of EITF Issue 97-4, "Deregulation of the Pricing of Electricity - Issues Related
to the Application of FASB Statements No. 71 and No. 101" (EITF 97-4).
Accordingly, we recorded an extraordinary charge to earnings of $804 million
(after tax), consisting primarily of the write-down of our nuclear and fossil
generating stations in accordance with SFAS 121. As a result of this impairment
analysis, the net book value of the generating stations was reduced by
approximately $5.0 billion (pre-tax) or $3.1 billion (net of tax). This amount
was offset by the creation of a $4.057 billion (pre-tax), or $2.4 billion (net
of tax) regulatory asset, as provided for in the Final Order and Finance Order.
In addition to the impairment of our electric generating stations, the
extraordinary charge consisted of various accounting adjustments to reflect
the absence of cost of service regulation in the electric generation portion
of our business. The adjustments primarily related to materials and supplies,
general plant items and liabilities for certain contractual and environmental
obligations.
In accordance with the Final Order, we also reclassified a $569 million
excess depreciation reserve related to our electric distribution assets from
Accumulated Depreciation to a Regulatory Liability. Such amount is being
amortized in accordance with the terms of the Final Order over the period from
January 1, 2000 to July 31, 2003.
Note 4. Regulatory Assets and Liabilities
At December 31, 2001 and 2000, respectively, we had deferred the
following regulatory assets and liabilities on the Consolidated Balance
Sheets:
December
--------------------------
2001 2000
---------- -----------
(Millions of Dollars)
Regulatory Assets
-----------------
Stranded Costs To Be Recovered................................ $4,105 $4,057
SFAS 109 Income Taxes......................................... 302 285
OPEB Costs.................................................... 212 232
Societal Benefits Charges (SBC)............................... 4 135
Environmental Costs........................................... 87 13
Unamortized Loss on Reacquired Debt and Debt Expense.......... 92 104
Underrecovered Gas Costs...................................... 120 --
39
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December
--------------------------
2001 2000
---------- -----------
(Millions of Dollars)
Regulatory Assets
-----------------
Unrealized Losses on Gas Contracts............................ 137 --
Non-Utility Generation Transition Charge (NTC)................ -- 7
Other......................................................... 161 162
---------- -----------
Total Regulatory Assets................................. $5,220 $4,995
========== ===========
Regulatory Liabilities
Excess Depreciation Reserve................................... $319 $444
Non-Utility Generation Transition Charge (NTC)................ 48 --
Overrecovered Gas Costs....................................... -- 26
Other......................................................... 6 --
---------- -----------
Total Regulatory Liabilities............................ $373 $470
========== ===========
Stranded Costs To Be Recovered: This reflects the deferred costs to be
recovered by the securitization transition charge, which was authorized by the
Final Order and Finance Order.
SFAS 109 Income Taxes: This amount represents the portion of deferred
income taxes that will be recovered through future rates, based upon
established regulatory practices, which permit the recovery of current taxes.
OPEB Costs: Includes costs associated with adoption of SFAS 106.
"Employers' Accounting for Benefits Other Than Pensions which were deferred in
accordance with EITF Issue 92-12, "Accounting for OPEB Costs by Rate Regulated
Enterprises". Prior to the adoption of SFAS 106, post-retirement benefits
costs were recognized on a cash basis. SFAS 106 required that these costs be
accrued as the benefits were earned. Accordingly a liability and a regulatory
asset were recorded for the total benefits earned at the implementation date.
Beginning January 1, 1998, we commenced the amortization of this regulatory
asset over 15 years. See Note 10. Pension, Other Postretirement Benefit and
Savings Plans for additional information.
Societal Benefits Charges (SBC): The SBC includes costs related to our
electric distribution business as follows: 1) social programs which include
the universal service fund; 2) nuclear plant decommissioning; 3) demand side
management (DSM) programs; 4) manufactured gas plant remediation; 5) consumer
education; 6) Under and overrecovered electric bad debt expenses; and 7) MTC
overrecovery.
Environmental Costs: Represents environmental investigation and
remediation costs which are probable of recovery in future rates.
Unamortized Loss on Reacquired Debt and Debt Expense: Represents bond
issuance costs, premiums, discounts and losses on reacquired long-term debt.
Underrecovered/Overrecovered Gas Costs: Represents gas costs in excess
of or below the amount included in rates and probable of recovery in the
future.
Unrealized Losses on Gas Contracts: This represents the recoverable
portion of unrealized losses associated with contracts used in the company's
gas distribution business.
Non-Utility Generation Transition Charge (NTC): This clause was
established to account for above market costs related to non-utility
generation contracts. The charge for the stranded NTC recovery was initially
set at $183 million annually. Any NUG contract costs and/or buyouts are
charged to the NTC. Proceeds from the sale of the energy and capacity
purchased under these NUG contracts are also credited to this account.
Other Regulatory Assets: Includes Decontamination and Decommissioning
Costs, Plant and Regulatory Study Costs, Repair Allowance Tax Deficiencies
and Interest, Property Abandonments, Oil and Gas Property Write-Down and
recovery of costs related to Transition Funding's interest rate swap.
40
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Excess Depreciation Reserve: As required by the BPU, we reduced our
depreciation reserve for our electric distribution assets by $569 million and
recorded such amount as a regulatory liability to be amortized over the period
from January 1, 2000 to July 31, 2003. In 2000 and 2001, $125 million was
amortized. The remaining $319 million will be amortized through July 1, 2003.
Other Regulatory Liabilities: This includes the following: 1) Interest
on amounts collected from customers that are used to fund incentives for
choosing a third party gas supplier; 2) Interest on amounts collected early
from customers relating to the Transitional Energy Facility Assessment tax;
and 3) Amounts collected from customers in order for Transition Funding to
obtain a AAA rating on its transition bonds.
Note 5. Schedule of Consolidated Capital Stock and Other Securities
Outstanding Current
Shares at Redemption
December 31, Price Per December 31, December 31,
2001 Share 2001 2000
--------------- ------------ -------------- ----------------
(Millions of Dollars)
PSE&G Preferred Securities
PSE&G Cumulative Preferred Stock (A) without
Mandatory Redemption (B) (C) $100 par value series
4.08%........................................... 146,221 103.00 $15 $15
4.18%........................................... 116,958 103.00 12 12
4.30%........................................... 149,478 102.75 15 15
5.05%........................................... 104,002 103.00 10 10
5.28%........................................... 117,864 103.00 12 12
6.92%........................................... 160,711 -- 16 16
$25 par value series
6.75%........................................... -- -- -- 15
------------- ----------------
Total Preferred Stock without Mandatory Redemption $80 $95
============= ================
With Mandatory Redemption (B) (C) $100
Par value series
5.97%........................................... -- -- $-- $75
------------- ----------------
Total Preferred Stock with Mandatory Redemption... $-- $75
============= ================
PSE&G Monthly Guaranteed Preferred Beneficial
Interest in PSE&G's Subordinated
Debentures (B) (C) (D)
9.375%.......................................... -- -- $-- $150
8.00%........................................... 2,400,000 25.00 60 60
------------- ----------------
Total Monthly Guaranteed Preferred Beneficial
Interest in PSE&G's Subordinated Debentures..... $60 $210
============= ================
PSE&G Quarterly Guaranteed Preferred Beneficial
Interest in PSE&G's Subordinated
Debentures (B) (C) (D)
8.625%.......................................... -- -- $-- $208
8.125%.......................................... 3,800,000 -- 95 95
------------- ----------------
Total Quarterly Guaranteed Preferred Beneficial
Interest in PSE&G's Subordinated Debentures..... $95 $303
============= ================
(A) At December 31, 2001, there were an aggregate of 6,704,766 aggregates
of shares of $100 par value and 10,000,000 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 our 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 revived from time to time.
41
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(B) At December 31, 2001 and 2000, the annual dividend requirement and
embedded dividend rate for our Preferred Stock without mandatory
redemption was $10,127,383 and 5.03%, $10,886,758 and 5.18%,
respectively, and for our Preferred Stock with mandatory redemption
was $1,119,375 and 6.02%, $4,477,500 and 6.02%, respectively.
At December 31, 2001 and 2000, the annual dividend requirement and
embedded cost of the Monthly Income Preferred Securities (Guaranteed
Preferred Beneficial Interest in our Subordinated Debentures) were
$7,768,750 and 4.90%, $18,862,500 and 5.50% respectively.
At December 31, 2001 and 2000, the annual dividend requirement of
the Quarterly Income Preferred Securities (Guaranteed Preferred
Beneficial Interest in our Subordinated Debentures) and our embedded
costs were $16,439,584 and 4.97%, $ 25,658,750 and 5.18%
respectively.
(C) For information concerning fair value of financial instruments, see
Note 7. Financial Instruments and Risk Management.
(D) PSE&G Capital L.P., PSE&G Capital Trust I and PSE&G Capital Trust II
were formed and are controlled by us for the purpose of issuing
Monthly and Quarterly Income Preferred Securities (Monthly and
Quarterly Guaranteed Preferred Beneficial Interest in our
Subordinated Debentures). The proceeds were loaned to us and are
evidenced by our Deferrable Interest Subordinated Debentures. If and
for as long as payments on our Deferrable Interest Subordinated
Debentures have been deferred, or we have defaulted on the
indentures related thereto or its guarantees thereof, we may not pay
any dividends on our common and preferred stock. The Subordinated
Debentures and the indentures constitute our full and unconditional
guarantee of the Preferred Securities issued by the partnership and
the trusts.
Note 6. Schedule of Consolidated Debt
LONG-TERM
December 31,
---------------------------------
Interest Rates Maturity 2001 2000
- ------------------------------------------------------ --------------------- -------------- ---------------
(Millions of Dollars)
PSE&G (excluding Transition Funding):
- -------------------------------------
First and Refunding Mortgage Bonds (A):
7.875% 2001................ - 100
6.125% 2002................ 258 258
6.875%-8.875% 2003................ 300 300
6.50% 2004................ 286 286
9.125% 2005................ 125 125
6.75% 2006 ............... 147 147
6.25% 2007 ............... 113 113
Variable 2008-2012........... - 66
6.75%-7.375% 2013-2017........... 330 330
6.45%-9.25% 2018-2022........... 139 139
Variable 2018-2022........... - 14
5.20%-7.50% 2023-2027........... 434 434
5.45%-6.55% 2028-2032........... 499 499
Variable 2028-2032........... - 25
5.00%-8.00% 2033-2037........... 160 160
Medium-Term Notes:
7.19% 2002................ 290 290
42
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8.10%-8.16% 2008-2012........... 60 60
7.04% 2018-2022........... 9 9
7.15%-7.18% 2023-2027........... 39 39
-------------- ---------------
Total First and Refunding Mortgage Bonds............................ 3,189 3,394
-------------- ---------------
Unsecured Bonds-7.43% 2002............... - 300
Unsecured Bonds-Variable 2027............... - 19
-------------- ---------------
Total Unsecured Bonds............................................... - 319
-------------- ---------------
Principal Amount Outstanding (B)............................................. 3,189 3,713
Amounts Due Within One Year (C).............................................. (547) (100)
Net Unamortized Discount..................................................... (16) (23)
-------------- ---------------
Total Long-Term Debt of PSE&G (excluding Transition
Funding) (D)....................................................... $2,626 $3,590
============== ===============
December 31,
---------------------------------
Interest Rates Maturity 2001 2000
- ------------------------------------------------------ --------------------- -------------- ---------------
Transition Funding (Millions of Dollars)
- ------------------
Securitization Bonds (E):
5.46%................................................ 2004................ $52 -
5.74%................................................ 2007................ 369 -
5.98%................................................ 2008................ 183 -
LIBOR plus 0.30%..................................... 2011................ 496 -
6.45%................................................ 2013................ 328 -
6.61%................................................ 2015................ 454 -
6.75%................................................ 2016................ 220 -
6.89%................................................ 2017................ 370 -
-------------- ---------------
Principal Amount Outstanding (B)............................................. 2,472 -
Amounts Due Within One Year (E).............................................. (121) -
-------------- ---------------
Total Long-Term Debt of Transition Funding............................ $2,351 -
-------------- ---------------
Total Long-Term Debt of PSE&G $4,977 $3,590
============== ===============
(A) Our First and Refunding Mortgage (Mortgage), securing the Bonds,
constitutes a direct first mortgage lien on substantially all of our
property and franchises.
(B) For information concerning fair value of financial instruments, see
Note 7. Financial Instruments and Risk Management.
(C) The aggregate principal amounts of mandatory requirements for
sinking funds and maturities for each of the five years following
December 31, 2001 are as follows:
Transition
Year PSE&G Funding Total
---------- --------- ----------- -------
2002..... $547 $-- $547
2003..... 300 -- 300
2004..... 286 52 338
2005..... 125 -- 125
2006..... 147 -- 147
--------- ----------- -------
$1,405 $52 $1,457
========= =========== =======
43
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(D) At December 31, 2001 and 2000, our annual interest requirement on
long-term debt of PSE&G was $220 million and $256 million, of which
$220 million and $233 million, respectively, was the requirement for
Mortgage Bonds. The embedded interest cost on long-term debt on such
dates was 7.46% and 7.30%, respectively. The embedded interest cost
on long-term debt due within one year at December 31, 2001 was
6.76%.
(E) On January 31, 2001, Transition Funding issued $2.525 billion of
Bonds in eight classes with estimated final payment dates from one
year to fifteen years. The net proceeds were remitted to us as
consideration for the property right in the TBC. At December 31,
2001, Transition Funding's annual interest requirement on the
securitization bonds was $148 million. The current portion of
Transition Funding's debt is based on estimated payment dates, with
final estimated payment dates at two years earlier than the final
maturity dates for each respective class of Bonds. At December 31,
2001, Transition Funding's annual interest requirement on its bonds
was $137 million.
SHORT-TERM (Commercial Paper and Bank Loans)
2001 2000 1999
----------- ----------- ----------
(Millions of Dollars)
Principal amount outstanding at year end, primarily commercial paper..... $-- $1,543 $1,475
Weighted average interest rate for short-term debt at year end........... -- 7.29% 6.56%
In March 2001, we reduced the maximum size of our commercial paper
program (Program) from $1.5 billion to $900 million. To provide back up
liquidity for this program, we maintain $900 million in revolving credit
facilities, each of which expire in June 2002. As of December 31, 2001, there
were no borrowings outstanding under these facilities. In addition, we have an
uncommitted line of credit with a bank. As of December 31, 2001, we had no
borrowings against our uncommitted line of credit.
Note 7. Financial Instruments and Risk Management
Our operations are exposed to market risks from changes in commodity
prices and interest rates that could affect our results of operations and
financial conditions. We manage our exposure to these market risks through our
regular operating and financing activities and, when deemed appropriate, hedge
these risks through the use of derivative financial instruments. We use the
term hedge to mean a strategy designed to manage risks of volatility in prices
or rate movements on certain assets, liabilities or anticipated transactions
and by creating a relationship in which gains or losses on derivative
instruments are expected to counterbalance the losses or gains on the assets,
liabilities or anticipated transactions exposed to such market risks. We use
derivative instruments as risk management tools consistent with our business
plans and prudent business practices and not for speculative purposes.
Fair Value of Financial Instruments
The estimated fair values were determined using the market quotations or
values of instruments with similar terms, credit ratings, remaining maturities
and redemptions at December 31, 2001 and December 31, 2000, respectively.
December 31, 2001 December 31, 2000
------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ ----------- ------------ -----------
(Millions of Dollars)
Long-Term Debt (A):
PSE&G................................................. 3,173 3,290 3,453
3,690
Transition Funding.................................... 2,472 2,575 -- --
44
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001 December 31, 2000
------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ ----------- ------------ -----------
(Millions of Dollars)
Preferred Securities Subject to Mandatory Redemption:
PSE&G Cumulative Preferred Securities................. -- -- 75 60
Monthly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 60 60 210 212
Quarterly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 95 96 303 304
(A) Includes current maturities. At December 31, 2001, Transition
Funding had an interest rate swap agreement outstanding with a
notional amount of $497 million. For additional information
regarding consolidated debt, see Note 6. Schedule of Consolidated
Debt. For additional information regarding preferred securities, see
Note 5. Schedule of Consolidated Capital Stock and Other Securities.
Commodity-Related Instruments
We use natural gas futures and swaps to reduce exposure to price
fluctuations from factors such as weather, changes in demand and changes in
supply to manage the price risk associated with gas supply to our customers.
These instruments, in conjunction with physical gas supply contracts, are
designed to cover estimated gas customer commitments. We have entered into 330
MMBTU of gas futures, swaps and options to hedge forecasted requirements. As of
December 31, 2001, the fair value of those instruments was $(137) million with a
maximum term of approximately one year. We utilize derivatives to hedge our gas
purchasing activities which, when realized, are recoverable through our LGAC.
Accordingly, the offset to the change in fair value of these derivatives is
recorded as a regulatory asset or liability.
As a result of the gas contract transfer that is anticipated to take
place in April 2002, our price risk relating to gas purchases will be
transferred to Power. As a result, after that date, we will not be utilizing
these derivative instruments in our gas distribution business.
Through the BGS auction, we have contracted for our expected peak load of
9,600 MW. If our peak load should exceed this amount or one of our suppliers
defaults on their contract, we may have to purchase power on the open market
and use commodity contracts during periods of high demand. To the extent that
the market prices exceed the auction contract price, the difference will be
deferred and collected from our customers as provided in the BPU Order
approving the auction process.
Given the absence of a PJM price cap in situations involving emergency
purchases and the potential for plant outages, extreme price movements can
occur and could have a material impact on our financial condition and net cash
flows.
Interest Rates
We are subject to the risk of fluctuating interest rates in the normal
course of business. Our policy is to manage interest rate risk through the use
of fixed rate debt, floating rate debt and interest rate swaps. As of December
31, 2001, a hypothetical 10% change in market interest rates would result in a
$4 million change in annual interest costs related to our short-term and
floating rate debt.
Transition Funding has entered into an interest rate swap on its sole
class of floating rate transition bonds. The notional amount of the interest
rate swap is approximately $497 million. The interest rate swap is indexed to
the three-month LIBOR rate. The fair value of the interest rate swap was
approximately $(18) million as of December 31, 2001 and was recorded as a
derivative liability, with an offsetting amount recorded as a regulatory asset
on the Consolidated Balance Sheet. This amount will vary over time as a result
of changes in market conditions.
45
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 8. Commitments and Contingent Liabilities
Hazardous Waste
The New Jersey Department of Environmental Protection (NJDEP) regulations
concerning site investigation and remediation require an ecological evaluation
of potential injuries to natural resources in connection with a remedial
investigation of contaminated sites. The NJDEP is presently working with
industry to develop procedures for implementing these regulations. These
regulations may substantially increase the costs of remedial investigations
and remediations, where necessary, particularly at sites situated on surface
water bodies. We and predecessor companies owned and/or operated certain
facilities situated on surface water bodies, certain of which are currently
the subject of remedial activities. The financial impact of these regulations
on these projects is not currently estimable. We do not anticipate that
compliance with these regulations will have a material adverse effect on our
financial position, results of operations or net cash flows.
Manufactured Gas Plant Remediation Program
We are currently working with the NJDEP under a program (Remediation
Program) to assess, investigate and, if necessary, remediate environmental
conditions at our former manufactured gas plant sites. To date, 38 sites have
been identified. The Remediation Program is periodically reviewed and revised
by us based on regulatory requirements, experience with the Remediation
Program and available remediation technologies. The long-term costs of the
Remediation Program cannot be reasonably estimated, but experience to date
indicates that approximately $20 million per year could be incurred over a
period of about 30 years since inception of the program in 1988 and that the
overall cost could be material. The costs for this remediation effort are
recovered through the SBC.
Net of insurance recoveries, costs incurred from January 1, 2001 through
December 31, 2001 for the Remediation Program amounted to approximately $22.8
million. Net of insurance recoveries, total project costs incurred through
December 31, 2001 for the Remediation Program amounted to approximately $164.6
million. In addition, at December 31, 2001, our estimated liability for
remediation costs through 2004, excluding insurance recoveries, aggregated $87
million. Expenditures beyond 2004 cannot reasonably be estimated.
Passaic River Site
The United States Environmental Protection Agency (EPA) has determined
that a six mile stretch of the Passaic River in the area of Newark, New
Jersey is a "facility" within the meaning of that term under the Federal
Comprehensive Environmental Response, Compensation and Liability Act of 1980
and that, to date, at least thirteen corporations, including us, may be
potentially liable for performing required remedial actions to address
potential environmental pollution at the Passaic River "facility." We and
certain of our predecessors conducted industrial operations at properties
within the Passaic River "facility." The operations include one operating
electric generating station, one former generating station, and four former
manufactured gas plant sites. We cannot predict what action, if any, the EPA
or any third party may take against it with respect to these matters, or in
such event, what costs it may incur to address any such claims. However, such
costs may be material.
46
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Minimum Lease Payments
We lease administrative office space under various operating leases with
future minimum lease payments of:
(Millions of Dollars)
2002 $3
2003 3
2004 2
2005 2
2006 2
Thereafter 1
-----------
Total minimum lease payments....... $13
===========
We have entered into a capital lease for administrative office space. The
total future minimum payments and present value of this capital lease as of
December 31, 2001 are:
(Millions of Dollars)
2002 $8
2003 8
2004 8
2005 8
2006 8
Thereafter 62
-----------
Total minimum lease payments........ 102
-----------
Less: Imputed Interest (42)
-----------
Present Value of net minimum lease payments $60
===========
Note 9. Income Taxes
A reconciliation of reported income tax expense with the amount computed
by multiplying pretax income by the statutory Federal income tax rate of 35%
is as follows:
2001 2000 1999
----------- ------------ ----------
(Millions of Dollars)
Net Income (Loss).......................................................... $235 $587 $(151)
Extraordinary Item (Net of Tax of $345)............................... -- -- 804
----------- ------------ ----------
Net Income before Extraordinary Item....................................... 235 587 653
----------- ------------ ----------
Income Taxes:
Federal - Current..................................................... 250 261 425
Deferred ................................................... (192) 50 (1)
ITC......................................................... (2) (1) (11)
----------- ------------ ----------
Total Federal............................................ 56 310 413
----------- ------------ ----------
State - Current....................................................... 42 150 109
Deferred...................................................... (9) (53) (12)
----------- ------------ ----------
Total State.............................................. 33 97 97
----------- ------------ ----------
Total ........................................................... 89 407 510
----------- ------------ ----------
Pretax income.............................................................. $324 $994 $1,163
=========== ============ ==========
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Reconciliation between total income tax provisions and tax computed at
the statutory tax rate on pretax income:
2001 2000 1999
----------- -------------- ------------
(Millions of Dollars)
Tax computed at the statutory rate......................................... $113 $348 $407
Increase (decrease) attributable to flow through of certain tax adjustments:
Plant Related......................................................... (41) (15) 35
Amortization of investment tax credits................................ (2) (1) (11)
New Jersey Corporate Business Tax..................................... 21 58 68
Other................................................................. (2) 17 11
----------- -------------- ------------
Subtotal......................................................... (24) 59 103
----------- -------------- ------------
Total income tax provisions...................................... $89 $407 $510
=========== ============== ============
Effective income tax rate.................................................. 27.5% 40.9% 43.9%
We provide deferred taxes 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 ratemaking purposes. Management believes that it is probable
that the accumulated tax benefits that previously have been treated as a
flow-through item to our customers will be recovered from utility customers
in the future. Accordingly, an offsetting regulatory asset was established.
As of December 31, 2001, we have a deferred tax liability and an offsetting
regulatory asset of $302 million representing the tax costs expected to be
recovered through future rates based upon established regulatory practices,
which permit recovery of current taxes. This amount was determined using the
enacted Federal income tax rate of 35% and State income tax rate of 9%.
SFAS 109
The following is an analysis of deferred income taxes:
December 31,
-------------------------------
2001 2000
------------- --------------
Deferred Income Taxes (Millions of Dollars)
- ---------------------
Assets:
Current (net)................................................ $21 $23
Non-current:
Unrecovered Investment Tax Credits......................... 19 20
New Jersey Corporate Business Tax.......................... 407 395
Other Post-Retirement Benefit Costs........................ 83 64
Market Transition Charge................................... 59 40
Total Non-current....................................... 568 519
------------- --------------
Total Assets............................................ 589 542
------------- --------------
Liabilities:
Non-current:
Plant Related Items........................................ 1,228 1,245
Securitization-EMP......................................... 1,594 1,657
Conservation Costs......................................... 24 124
Pension Costs.............................................. 70 55
Taxes Recoverable Through Future Rates (Net)............... 130 90
Other (Net)................................................ 17 (10)
------------- --------------
Total Non-current....................................... 3,063 3,161
------------- --------------
Total Liabilities....................................... 3,063 3,161
------------- --------------
Summary--Deferred Income Taxes
Net Current Asset............................................ 21 23
Net Non-current Liability.................................... 2,495 2,642
------------- --------------
Total................................................... $2,474 $2,619
============= ==============
47
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The balance of Federal income tax receivable from PSEG was $16 million and
$12 million as of December 31, 2001 and December 31, 2000, respectively.
Note 10. Pension, Other Postretirement Benefit and Savings Plans
Our employees participate in non-contributory pension plans sponsored by
PSEG and administered by PSEG Services Corporation. In addition, PSEG
sponsors two defined contribution plans. Our represented employees are
eligible for participation in the PSEG Employee Savings Plan (Savings Plan),
while our non-represented employees are eligible for participation in the
PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). These plans are
401(k) plans to which eligible employees may contribute up to 25% of their
compensation. Employee contributions up to 7% for Savings Plan participants
and up to 8% for Thrift Plan participants are matched with employer
contributions of cash or PSEG common stock equal to 50% of such employee
contributions. For periods prior to March 1, 2002, employer contributions
related to participant contributions in excess of 5% and up to 7%, were made
in shares of PSEG common stock for Savings Plan participants. For periods
prior to March 1, 2002, employer contributions, related to participant
contributions in excess of 6% and up to 8%, were made in shares of PSEG
common stock for Thrift Plan participants. Beginning on March 1, 2002, and
thereafter, all employer contributions will be made in cash to each plan.
Pension costs amounted to $30 million and $17 million for the years ended
December 31, 2001 and 2000, respectively. Thrift and Savings Plan matching
costs amounted to approximately $12 million and $11 million for the years
ended December 31, 2001 and 2000, respectively.
SFAS No. 106, which requires that the expected cost of employees'
postretirement health care and life insurance benefits, also referred to as
other postretirement benefits (OPEB), be charged to income during the years in
which employees render service. Such costs were deferred through December 31,
1997, pursuant to an order from the BPU. In concert with the discontinuance of
SFAS 71, the portion of the resulting regulatory asset allocated to Power prior
to the transfer of the electric generation assets remained with us as recovery
of these previously incurred costs will be through our regulated transmission
and distribution operations. OPEB costs amounted to $95 million and $109 million
for the years ended December 31, 2001 and 2000, respectively.
Note 11. Financial Information by Business Segments
Basis of Organization
The reportable segments were determined by Management in accordance with
SFAS No. 131, "Disclosures About Segments of an Enterprise and Related
Information" (SFAS 131). The separation of the electric segment data prior to
August 1, 1999 into our Generation, Energy Resources and Trade and
Transmission and Distribution segments was based on estimates and
allocations.
Generation
This segment earns revenue through the sale of our energy and capacity.
Effective with the transfer of our generation-related assets to Power in
August 2000, we have no further operations in this segment.
Trading
This segment markets electricity, capacity, ancillary services and
natural gas products on a wholesale basis throughout the Eastern and
Midwestern United States. Effective with the transfer of our
generation-related assets in August 2000, we have no further operations in
this segment.
48
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Transmission and Distribution (T&D)
This segment represents our provision of regulated utility services. The
electric transmission and electric and gas distribution segment of our
business generates revenue from our tariffs under which we provide such
services to residential, commercial and industrial customers in New Jersey.
The rates charged for electric transmission are regulated by FERC while the
rates charged for electric and gas distribution are regulated by the BPU.
Revenues are also earned from a variety of other activities such as sundry
sales, the appliance service business, wholesale transmission services and
other miscellaneous services.
Information related to the segments of our business is detailed below:
Consolidated
Generation Trading T&D Total
------------- --------- --------- -------------
For the Year Ended December 31,
2001:
- -------------------------------------
Total Operating Revenues............. $-- $-- $6,091 $6,091
Depreciation and Amortization........ -- -- 384 384
Interest Income...................... -- -- 21 21
Net Interest Charges................. -- -- 356 356
Operating Income Before Income -- -- 324 324
Taxes................................
Income Taxes......................... -- -- 89 89
Segment Net Income................... -- -- 235 235
Gross Additions to Long-Lived Assets. -- -- 398 398
As of December 31, 2001:
- -------------------------------------
Total Assets......................... $-- $-- $12,936 $12,936
For the Year Ended December 31,
2000:
Total Operating Revenues............. $1,110 $1,521 $4,728 $7,359
Depreciation and Amortization........ 77 -- 214 291
Interest Income...................... 1 -- 21 22
Net Interest Charges................. 46 -- 208 254
Operating Income Before Income 310 46 638 994
Taxes................................
Income Taxes......................... 128 19 260 407
Segment Net Income (Loss)............ 182 27 378 587
Gross Additions to Long-Lived Assets. -- -- 401 401
As of December 31, 2000:
- -------------------------------------
Total Assets...................... $-- $-- $15,267 $15,267
For the Year Ended December 31,
1999:
- -------------------------------------
Total Operating Revenues............. $2,602 $1,842 $3,196 $7,640
Depreciation and Amortization........ 224 -- 305 529
Interest Income...................... -- -- 12 12
Net Interest Charges................. 112 -- 275 387
Operating Income Before Income 768 39 356 1,163
Taxes................................
Income Taxes......................... 275 16 219 510
Segment Income before 493 23 137 653
Extraordinary Item...................
Extraordinary Item (A)............... (3,204) -- 2,400 (804)
Segment Net Income (Loss)............ (2,711) 23 2,537 (151)
Gross Additions to Long-Lived Assets. 92 -- 387 479
(A) See Note 3. Regulatory Issues and Accounting Impact of Deregulation
for discussion of the extraordinary charge recorded by the generation segment
in 1999 and the related regulatory asset for securitization recorded by the
T&D segment.
49
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12. Property, Plant and Equipment and Jointly Owned Facilities
We have ownership interests in and are responsible for providing our
share of the necessary financing for the following jointly owned facilities.
All amounts reflect the share of our jointly owned projects and the
corresponding direct expenses are included in the Statements of Income as
operating expenses.
Information related to our Property, Plant and Equipment is detailed below:
2001 2000
--------------- -----------------
Property, Plant and Equipment
Electric Plant in Service:
Transmission........................... $1,201 $1,183
Distribution........................... 4,254 4,056
--------------- -----------------
Total Electric Plant in Service... 5,455 5,239
--------------- -----------------
Construction Work in Progress............ 26 43
Plant Held for Future Use................ 20 20
--------------- -----------------
Total Electric Plant ............. 5,501 5,302
--------------- -----------------
Gas Plant in Service:
Transmission........................... 74 69
Distribution........................... 3,121 2,978
Other.................................. 89 130
--------------- -----------------
Total Gas Plant in Service........ 3,284 3,177
--------------- -----------------
Other Plant in Service................... 385 420
--------------- -----------------
Total Property, Plant and Equipment $9,170 $8,899
=============== =================
Information related to Jointly Owned Facilities is detailed below:
Plant - December 31, 2001 Plant - December 31, 2000
------------------------------------------------------------
Ownership Accumulated Accumulated
Interest Plant Depreciation Plant Depreciation
------------- ------------------------------------------------------------
(Millions of Dollars)
Transmission Facilities... Various $80 $30 $97 $33
Linden SNG Plant.......... 90.00% 5 4 16 15
50
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 13. Selected Quarterly Data (Unaudited)
The information shown below, in our opinion, 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 Quarter Ended
----------------------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
--------------------- --------------------- --------------------- ----------------------
2001 2000 2001 2000 2001 2000 2001 2000
---------- ---------- ---------- ---------- ---------- ---------- ---------- -----------
(Millions of Dollars)
Operating Revenues........... $1,952 $2,265 $1,311 $1,992 $1,395 $1,466 $1,433 $1,636
Operating Income............. 247 522 150 361 160 214 125 171
Net Income................... 112 250 32 152 65 99 27 86
Earnings Available to PSEG... 109 248 31 150 65 97 26 84
Note 14. Related-Party Transactions
In August 2000, we transferred our electric generating assets to Power in
exchange for a $2.786 billion Promissory Note. Interest on the Promissory Note
was payable at an annual rate of 14.23%, which represented our weighted
average cost of capital. For the period from January 1, 2001 to January 31,
2001, we recorded interest income of approximately $34 million relating to the
Promissory Note. Power repaid the Promissory Note on January 31, 2001.
In addition, on January 31, 2001, we loaned $1.084 billion to PSEG at
14.23% per annum and recorded interest income of approximately $33 million
relating to the loan in 2001. PSEG repaid the loan on April 16, 2001. We also
returned $2.265 billion of capital to PSEG on January 31, 2001 utilizing
proceeds from the $2.525 billion securitization transaction and the generation
asset transfer, as required by the Final Order, as part of the
recapitalization. (See Note 3. Regulatory Issues and Accounting Impacts of
Deregulation).
Effective with the transfer of the electric generation business, Power
charges us for MTC and the energy and capacity provided to meet our BGS
requirements. For the years ended December 31, 2001 and 2000, we were charged
by Power approximately $2 billion and $0.8 billion for MTC and BGS. As of
December 31, 2001 and 2000, our payable to Power relating to these costs was
approximately $158 million and $159 million. For the years ended December 31,
2001 and 2000, we sold energy and capacity to Power at the market price of
approximately $158 million and $78 million, which we purchased under various
NUG contracts at costs above market prices. As of December 31, 2001 and 2000,
our receivable related to these purchases was approximately $7 million and $17
million. As a result of the Final Order, we have established an NTC to recover
the above market costs related to these NUG contracts. The difference between
our costs and recovery of costs through the NTC and sales to Power, which are
priced at the locational marginal price (LMP) set by the PJM ISO for energy
and at wholesale market prices for capacity, is deferred as a regulatory
asset.
PSEG Services Corporation provides and bills administrative services to
us on a monthly basis. Our costs related to such service amounted to
approximately $385 million for the year ended December 31, 2001. As of
December 31, 2001 our related party payable related to these costs was
approximately $37 million.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
FINANCIAL STATEMENT RESPONSIBILITY
Our management is responsible for the preparation, integrity and
objectivity of our consolidated financial statements and related notes. 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 our 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 our 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 PSEG Services conducts audits and
appraisals of accounting and other operations and evaluates the effectiveness
of cost and other controls and, where appropriate, recommends to management
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, 2001, the corporation's system
of internal accounting controls was adequate to accomplish the objectives
discussed herein.
The Board of Directors carries out its responsibility of financial
overview through the Audit Committee of PSEG, which presently consists of six
directors who are not our employees of or employees of any of our affiliates.
The PSEG 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 all times.
E. JAMES FERLAND ROBERT E. BUSCH
Chairman of the Board and Senior Vice President - Finance
Chief Executive Officer and Chief Financial Officer
PATRICIA A. RADO
Vice President and Controller
(Chief Accounting Officer)
February 15, 2002
51
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
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
and Gas Company and its subsidiaries (the "Company") as of December 31, 2001 and
2000, and the related consolidated statements of income, common stockholder's
equity and cash flows for each of the three years in the period ended December
31, 2001. Our audits also included the consolidated financial statement schedule
listed in the Index in Item 14(B)(a). These consolidated financial statements
and the consolidated financial statement schedule are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements and the consolidated financial statement
schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of the Company as of
December 31, 2001 and 2000, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 2001 in
conformity with accounting principles generally accepted in the United States
of America. Also, in our opinion, such consolidated financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects, the
information set forth therein.
We have previously audited, in accordance with auditing standards
generally accepted in the United States of America, the consolidated balance
sheets of the Company as of December 31, 1999, 1998, and 1997, and the
related consolidated statements of income, common stockholder's equity and
cash flows for the years ended December 31, 1998 and 1997 (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, 2001, 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
Parsippany, New Jersey
February 15, 2002
52
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
OF THE REGISTRANTS
Directors
Below is shown as to each present director information recording each
director's period of service as a director of PSE&G, age as of April 16, 2002,
present committee memberships, business experience during the last five years
and other present directorships.
E. JAMES FERLAND has been a director since 1986. Age 60. and has been
Chairman of the Board, President and Chief Executive Officer of PSEG since
July 1986, Chairman of the Board and Chief Executive Officer of PSE&G since
July 1986, Chairman of the Board and Chief Executive Officer of Energy
Holdings since June 1989, Chairman of the Board and Chief Executive Officer of
Power since June 1999 and Chairman of the Board and Chief Executive Officer of
Services since November 1999. Director of Foster Wheeler Ltd.
ALBERT R. GAMPER, JR. has been a director since December 2000. Age 59.
Director of PSEG. Has been President and Chief Executive Officer of the CIT
Group, Inc., Livingston, New Jersey (commercial finance company), since
February 2002. Was President and Chief Executive Officer of Tyco Capital
Corporation from June 2001 to February 2002. Was Chairman of the Board,
President and Chief Executive Officer of the CIT Group, Inc., from January
2000 to June 2001. Was President and Chief Executive Officer of the CIT Group,
Inc. from December 1989 to December 1999. During 2001, Albert R. Gamper, Jr. was
late in filing a Form 3 in accordance with the requirements of Section 16(a)
of the Securities and Exchange Act of 1934, as amended, to report any
ownership of PSE&G Preferred Stock, upon election as a Director. At the time
of his election as a Director, Mr. Gamper did not own any Preferred Stock.
CONRAD K. HARPER has been a director since May 1997. Age 61. Director of
PSEG. Has been a partner in the law firm of Simpson Thacher & Bartlett, New
York, New York since October 1996 and from 1974 to May 1993. Was Legal
Adviser, U.S. Department of State from May 1993 to June 1996. Director of New
York Life Insurance Company.
MARILYN M. PFALTZ has been a director since 1980. Age 69. Director of
PSEG. Has been a partner of P and R Associates, Summit, New Jersey
(communications specialists), since 1968. Director of AAA National
Association, AAA Investment Company, AAA Life Re Ltd. and Beacon Trust
Company.
53
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Executive Officers
The following table sets forth certain information concerning the
executive officers of PSE&G.
============================================================================================================================
AGE EFFECTIVE DATE FIRST ELECTED
NAME DECEMBER 31, 2001 OFFICE TO PRESENT POSITION
============================================================================================================================
E. James Ferland 59 Chairman of the Board and Chief July 1986 to present
Executive Officer (PSE&G)
----------------------------------------------------------------------------------------------------------------------------
R. Edwin Selover 56 Senior Vice President and General January 1988 to present
Counsel (PSE&G)
----------------------------------------------------------------------------------------------------------------------------
Alfred C. Koeppe 55 President and Chief Operating February 2000 to present
Officer (PSE&G)
Senior Vice President--Corporate October 1996 to February 2000
Services and External Affairs (PSE&G)
Senior Vice President--External October 1995 to October 1996
Affairs (PSE&G)
----------------------------------------------------------------------------------------------------------------------------
Robert E. Busch 55 Senior Vice President and March 1998 to present
Chief Financial Officer (PSE&G)
----------------------------------------------------------------------------------------------------------------------------
Patricia A. Rado 59 Vice President and Controller April 1993 to present
(PSE&G)
----------------------------------------------------------------------------------------------------------------------------
ITEM 11. EXECUTIVE COMPENSATION
Information regarding the compensation of the Chief Executive Officer and
the four most highly compensated executive officers of PSE&G as of December
31, 2001 is set forth below. Amounts shown were paid or awarded for all
services rendered to PSEG and its subsidiaries and affiliates including PSE&G.
===================================================================================================================
Long Term Compensation
-----------------------------------
Annual Compensation Awards Payouts
--------------------------------------------------------------
Bonus/Annual LTIP All Other
Incentive Restricted Options Payouts Compensation
Name and Principal Position Year Salary $ Award ($)(1) Stock ($) (#) (2) ($) (3) ($) (4)
-------------------------------------------------------------------------------------------------------------------
E. James Ferland 2001 962,525 1,023,000 2,248,000(5) 350,000 400,800 51,152
Chairman of the Board and Chief 2000 890,000 1,001,300 0 300,000 361,440 59,037
Executive Officer 1999 815,000 733,500 0 215,000 304,720 29,292
-------------------------------------------------------------------------------------------------------------------
R. Edwin Selover 2001 367,852 225,000 0 70,000 100,200 6,867
Senior Vice President and 2000 325,000 170,600 0 40,000 81,324 17,280
General Counsel 1999 310,000 162,800 0 35,000 65,632 12,828
-------------------------------------------------------------------------------------------------------------------
Alfred C. Koeppe 2001 358,654 270,000 0 75,000 100,200 6,803
President and Chief Operating 2000 340,000 255,000 0 310,000 90,360 6,805
Officer 1999 290,000 152,300 0 75,000 75,008 6,404
-------------------------------------------------------------------------------------------------------------------
Robert E. Busch 2001 335,482 262,500 0 315,000 60,120 6,803
Senior Vice President and 2000 300,000 157,500 0 40,000 0 6,805
Chief Financial Officer 1999 275,000 144,400 0 26,500 0 6,402
-------------------------------------------------------------------------------------------------------------------
Patricia A. Rado 2001 209,835 94,500 0 25,000 24,048 6,449
Vice President and Controller 2000 200,000 90,000 0 15,000 18,072 7,289
1999 192,000 72,000 0 15,000 18,072 6,609
-------------------------------------------------------------------------------------------------------------------
54
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(1) Amount awarded in 2001 was earned under the Restated and Amended
Management Incentive Compensation Plan and in 2000 and 1999 was earned
under the Management Incentive Compensation Plan and determined and
paid in the following year based on individual performance and
financial and operating performance of PSEG and us, including
comparison to other companies.
(2) All grants of options to purchase shares of PSEG Common Stock were
non-qualified options made under the 1989 Long-Term Incentive Plan
(1989 LTIP) or the 2001 Long-Term Incentive Plan (2001 LTIP). All
options granted were non-tandem. Non-tandem grants are made without
performance units and dividend equivalents.
(3) Amount paid in proportion to options exercised, if any, based on
value of previously granted performance units and dividend
equivalents under the 1989 LTIP, each as measured during three-year
period ending the year prior to the year in which payment is made.
Under the 1989 LTIP, tandem grants are made with an equal number of
performance units and dividend equivalents which may provide cash
payments, dependent upon future financial performance of PSEG in
comparison to other companies and dividend payments by PSEG, to assist
recipients in exercising options granted. The tandem 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.
(4) Includes employer contribution to the Thrift and Tax-Deferred
Savings Plan:
========================================================================================================
Ferland Selover Koeppe Busch Rado
--------------------------------------------------------------------------------------------------------
Year ($) ($) ($) ($) ($)
--------------------------------------------------------------------------------------------------------
2001 5,102 5,104 6,803 6,803 6,449
--------------------------------------------------------------------------------------------------------
2000 5,102 4,747 6,805 6,805 6,422
--------------------------------------------------------------------------------------------------------
1999 4,801 4,802 6,404 6,402 6,390
========================================================================================================
In addition, 2001, 2000 and 1999 amounts include for Mr. Ferland,
$46,050, $53,935, and $24,491; for Mr. Selover $1,763, $12,533, and
$8,026; and for Mrs. Rado $0, $867, and $219, respectively,
representing earnings credited on compensation deferred under PSE&G's
Deferred Compensation Plan in excess of 120% of the applicable
Federal long-term interest rate as prescribed under Section 1274(d)
of the Internal Revenue Code. Prior to January 1, 2000, under our
Deferred Compensation Plan, interest is paid at prime rate plus 1/2%,
adjusted quarterly. Effective January 1, 2000, the Plan was amended
to permit participants to select from among four additional
investment options for compensation that is deferred.
(5) Value as of original grant date, based on the closing price of
$40.80 on the New York Stock Exchange on November 20, 2001, with
respect to an award to Mr. Ferland of 60,000 shares of restricted
stock, of which 30,000 shares vest in 2006 and 30,000 shares vest in
2007. Dividends on the entire grant are paid in cash from the date
of award.
==========================================================================================================
OPTION GRANTS IN LAST FISCAL YEAR (2001)
==========================================================================================================
Number of % of Total
Securities Options
Underlying Granted to Exercise or Grant Date
Options Employees in Base Price Expiration Present Value
Name Granted Fiscal Year ($/Sh) Date ($) (3)
----------------------------------------------------------------------------------------------------------
E. James Ferland 350,000(1) 12.4 40.78 12/18/11 2,205,000
----------------------------------------------------------------------------------------------------------
R. Edwin Selover 70,000 2.5 40.78 12/18/11 441,000
----------------------------------------------------------------------------------------------------------
Alfred C. Koeppe 75,000(1) 2.6 40.78 12/18/11 472,500
----------------------------------------------------------------------------------------------------------
Robert E. Busch 65,000(1) 2.3 40.78 12/18/11 409,500
250,000(2) 8.8 46.23 4/24/11 1,880,000
----------------------------------------------------------------------------------------------------------
Patricia A. Rado 25,000 0.9 40.78 12/18/11 157,500
==========================================================================================================
55
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
(1) Granted under LTIP with exercisability commencing December 18, 2002,
December 18, 2003 and December 18, 2004, respectively, with respect to
one-third of the options at each such date.
(2) Granted under 1989 LTIP not in tandem with performance units and dividend
equivalents, with exercisability commencing April 24, 2002, April 24,
2003, April 24, 2004, April 24, 2005 and April 24, 2006, respectively,
with respect to one-fifth of the options at each such date.
(3) Determined using the Black-Scholes model, incorporating the following
material assumptions and adjustments: (a) exercise prices of $40.78 and
$46.23, equal to the fair market value of the underlying PSEG Common
Stock on the respective dates of grant; (b) an option term of ten years
on all grants; (c) interest rates of 5.02% and 5.14% that represent the
interest rates on U.S. Treasury securities on the respective dates of
grant with a maturity date corresponding to that of the option terms; (d)
volatility of 26.07% and 25.30% calculated using daily PSEG Common Stock
prices for the one-year period prior to the respective grant dates; (e)
dividend yields of 5.30% and 4.67% and (f) reductions of approximately
7.38% and 11.38% to reflect the probability of forfeiture due to
termination prior to vesting, and approximately 8.70% and 9.78% to
reflect the probability of a shortened option term due to termination of
employment prior to the option expiration dates. Actual values which may
be realized, if any, upon any exercise of such options, will be based on
the market price of PSEG Common Stock at the time of any such exercise
and thus are dependent upon future performance of PSEG Common Stock.
There is no assurance that any such value realized will be at or near the
value estimated by the Black-Scholes model utilized.
==================================================================================================================
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR (2001)
AND FISCAL YEAR END OPTION VALUES (12/31/01)
------------------------------------------------------------------------------------------------------------------
Value of Unexercised
Number of Unexercised In-the-Money Options
Options at FY-End (#) (1) At FY-End ($) (3)
-------------------------------------------------------------
-------------------------------------------------------------
Shares
Acquired Value
on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
Name (#)(1) ($)(2) (#) (#) ($) (3) ($) (3)
------------------------------------------------------------------------------------------------------------------
E. James Ferland 10,000 122,875 493,333 621,667 2,993,689 1,143,161
------------------------------------------------------------------------------------------------------------------
R. Edwin Selover 2,500 29,419 71,667 108,333 409,726 204,461
------------------------------------------------------------------------------------------------------------------
Alfred C. Koeppe 2,500 29,344 155,000 340,000 651,463 332,375
------------------------------------------------------------------------------------------------------------------
Robert E. Busch 1,500 10,575 45,000 350,000 194,249 167,189
------------------------------------------------------------------------------------------------------------------
Patricia A. Rado 600 6,838 23,000 40,000 113,670 80,575
==================================================================================================================
(1) Does not reflect any options granted and/or exercised after year-end
(12/31/01). The net effect of any such grants and exercises is
reflected in the table appearing under Security Ownership of
Directors, Management and Certain Beneficial Owners.
(2) Represents difference between exercise price and market price of
PSEG Common Stock on date of exercise.
(3) Represents difference between market price of PSEG Common Stock and
the respective exercise prices of the options at fiscal year end
(12/31/01). 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 PSEG Common Stock at
the time of any such exercise and thus are dependent upon future
performance of PSEG Common Stock.
Employment Contracts and Arrangements
PSEG has entered into an employment agreement dated as of June 16, 1998
and amended as of November 20, 2001 (Agreement) with Mr. Ferland covering his
employment as Chief Executive Officer through March 31, 2007. Under the
Agreement, Mr. Ferland has agreed not to retire prior to March 31, 2002, but
may retire thereafter. The Agreement provides that Mr. Ferland will be
re-nominated for election as a Director during his employment under the
Agreement. The Agreement provides that Mr. Ferland's base salary, target
annual incentive bonus and long term incentive bonus will be determined based
on compensation practices for CEO's of similar companies and that his annual
salary will not be reduced during the term of the Agreement. The Agreement
also provided for an award to him of 150,000 shares of restricted PSEG Stock
as of June 16, 1998 and 60,000 shares of restricted PSEG Common
56
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Stock as of November 20, 2001, of which 60,000 shares vest in 2002; 20,000
shares vest in 2003; 30,000 shares vest in 2004; 40,000 shares vest in 2005;
30,000 shares vest in 2006; and 30,000 shares vest in 2007. Any non-vested
shares are forfeited upon his retirement unless the Board of Directors, in its
discretion, determines to waive the forfeiture.
The Agreement provides for the granting of 22 years of pension credit
for Mr. Ferland's prior service, which was awarded at the time of his initial
employment. The Agreement further provides that if Mr. Ferland is terminated
without "Cause" or resigns for "Good Reason" (as those terms are defined in
the Agreement) during the term of the Agreement, the entire restricted stock
award immediately vests, he will be paid a benefit of two times base salary
and target bonus and his welfare benefits will be continued for two years
unless he is sooner employed. In the event such a termination occurs after a
"Change in Control" (also as defined in the Agreement), the payment to Mr.
Ferland becomes three times the sum of salary and target bonus, continuation
of welfare benefits for three years unless sooner reemployed, payment of the
net present value providing three years additional service under PSEG's
retirement plans, and a gross-up for excise taxes on any termination payments
due under the Internal Revenue Code. The Agreement provides that Mr. Ferland
is prohibited from competing with or recruiting employees from PSEG or its
subsidiaries of affiliates for two years after termination of employment.
Violation of these provisions requires a forfeiture of a portion of the
restricted stock grant and certain other benefits.
We have entered into an employment agreement with Mr. Koeppe dated as of
October 17, 2000 and Mr. Busch dated as of April 24, 2001, covering the
respective employment of each in the position listed in the Summary
Compensation Table through October 16, 2005 for Mr. Koeppe and April 24, 2006
for Mr. Busch. The agreements are essentially identical and provide that the
base salary, target annual incentive bonus and long-term incentive bonus will
be determined based on compensation practices of similar companies and that
their annual salary will not be reduced during the term of the Agreement, and
annually awards to Mr. Koeppe 50,000 options on PSEG Common Stock from 2001
through 2005 which vest each October 17 and expire on October 17, 2010 and
annually awards to Mr. Busch 50,000 options on PSEG Common Stock from 2002
through 2006 which vest each April 24 and expire on April 24, 2011.
The Agreements further provide that if the individual is terminated
without "Cause" or resigns for "Good Reason" (as those terms are defined in
each Agreement) during the term of the Agreement, the entire option award
becomes vested, the individual will be paid a benefit of two times base
salary and target bonus, and his welfare benefits will be continued for two
years unless he is sooner employed. In the event such a termination occurs
after a "Charge in Control" (also as defined in the Agreement), the payment
to the individual becomes three times the sum of salary and target bonus,
continuation of welfare benefits for three years unless sooner reemployed,
payment of the net present value of providing three years additional service
under our retirement plans, and a gross-up for excise taxes on any
termination payments due under the Internal Revenue Code. The Agreements
provide that the individual is prohibited for one year from competing with
and for two years from recruiting employees from, PSEG or its subsidiaries or
affiliates, after termination of employment. Violation of these provisions
requires a forfeiture of certain benefits.
The agreement for Messrs. Busch and Koeppe also provide for the grant of
additional years of credited service for retirement purposes in light of
allied work experience of fifteen years and twenty-five years, respectively.
Compensation Committee Interlocks and Insider Participation
We do not have a compensation committee. Decisions regarding
compensation of our executive officers are made by the Organization and
Compensation Committee of PSEG. Hence, during 2001 the PSE&G Board of
Directors did not have, and no officer, employee or former officer of us
participated in any deliberations of such Board, concerning executive officer
compensation.
Compensation of Directors and Certain Business Relationships
During 2001, a director who was not an officer of PSEG or its
subsidiaries and affiliates, including us, was paid an annual retainer of
$30,000 and a fee of $1,500 for attendance at any Board or Committee meeting,
inspection trip, conference or other similar activity relating to PSEG or us.
Fifty percent of the annual retainer is paid in PSEG Common Stock. No
additional retainer is paid for service as a director of PSE&G. Each
Committee Chair receives an additional annual retainer of $3,000.
57
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
PSEG also maintains a Stock Plan for Outside Directors pursuant to which
directors who are not employees of PSEG or its subsidiaries receive 600
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 in Item
12 below under the heading Security Ownership of Certain Beneficial Owners
and Management.
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 after a "Change in
Control" as defined in the Plan or if the director were to die in office.
PSEG 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
The table below illustrates annual retirement benefits for executive
officers 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.
================================================================================
PENSION PLAN TABLE
- --------------------------------------------------------------------------------
Length of Service
Average Final -----------------------------------------------------------------
Compensation 30 Years 35 Years 40 Years 45 Years
- -------------- ----------------- --------------- ---------------- --------------
$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
1,100,000 660,000 715,000 770,000 825,000
1,200,000 720,000 780,000 840,000 900,000
1,300,000 780,000 845,000 910,000 975,000
1,400,000 840,000 910,000 980,000 1,050,000
1,500,000 900,000 975,000 1,050,000 1,125,000
================================================================================
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 150% of the average annual salary for such five year period. Messrs.
Ferland, Selover, Koeppe, Busch and Mrs. Rado will have accrued approximately
48, 43, 46, 34, and 29 years of credited service, respectively, as of age 65.
58
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
All of PSE&G's 132,450,344 outstanding shares of Common Stock are owned
beneficially and of record by PSE&G's parent, PSEG, 80 Park Plaza, P.O. Box
1171, Newark, New Jersey.
The following table sets forth beneficial ownership of PSEG Common Stock,
including options, by the directors and executive officers named below as of
February 22, 2002. None of these amounts exceed 1% of the PSEG Common Stock
outstanding at such date. No director or executive officer owns any of our
Preferred Stock of any class.
=====================================================================================
Amount and Nature of
Name Beneficial Ownership
- -------------------------------------------------------------------------------------
E. James Ferland.............................................. 1,410,442 (1)
R. Edwin Selover.............................................. 194,591 (2)
Alfred R. Koeppe.............................................. 504,608 (3)
Robert E. Busch............................................... 396,709 (4)
Patricia A. Rado.............................................. 71,480 (5)
Albert R. Gamper, Jr.......................................... 2,443 (6)
Conrad K. Harper.............................................. 3,922 (7)
Marilyn M. Pfaltz............................................. 12,179 (8)
All directors and executive officers as a group (8 persons)... 2,596,374
=====================================================================================
(1) Includes the equivalent of 13,395 shares held under PSEG Thrift and
Tax-Deferred Savings Plan. Includes options to purchase 1,115,000
shares, 493,333 of which are currently exercisable. Includes 210,000
shares of restricted stock, which vest as described in the Summary
Compensation Table Note 5.
(2) Includes options to purchase 180,000 shares, 71,667 of which are
currently exercisable.
(3) Includes the equivalent of 2,508 shares held under the PSE&G Thrift
and Tax-Deferred Savings Plan. Includes options to purchase 495,000
shares, 155,000 of which are currently exercisable.
(4) Includes the equivalent of 153 shares held under PSEG Thrift and
Tax-Deferred Savings Plan. Includes options to purchase 395,000
shares, 45,000 of which are currently exercisable.
(5) Includes the equivalent of 5,806 shares held under PSEG Thrift and
Tax-Deferred Savings Plan. Includes options to purchase 63,000
shares, 23,000 of which are currently exercisable.
(6) Includes 600 shares of restricted stock awarded pursuant to the
Stock Plan for Outside Directors described below.
(7) Includes 2,400 shares of restricted stock awarded pursuant to the
Stock Plan for Outside Directors described below.
(8) Includes 5,755 shares of restricted stock awarded pursuant to the
Stock Plan for Outside Directors described below.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS
None.
59
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K
(A) Financial Statements:
a. PSE&G Consolidated Statements of Income for the years ended
December 31, 2001, 2000 and 1999 on page 29.
PSE&G Consolidated Balance Sheets for the years ended December
31, 2001 and 2000 on pages 30 and 31.
PSE&G Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999 on page 32.
PSE&G Statements of Common Stockholder's Equity for the years
ended December 31, 2001, 2000 and 1999 on page 33.
PSE&G Notes to Consolidated Financial Statements on pages 34
through 51.
(B) The following documents are filed as a part of this report:
a. PSE&G Financial Statement Schedules:
Schedule II--Valuation and Qualifying Accounts for each of the
three years in the period ended December 31, 2001 (page 61).
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.
The following exhibits are filed herewith:
(1) PSE&G:
Exhibit 12: Computation of Ratios of Earnings to Fixed Charges
Exhibit 12(a): Computation of Ratios of Earnings to Fixed Charges
Plus Preferred Stock Dividend Requirements
Exhibit 23: Independent Auditors' Consent
(See Exhibit Index on pages 63 through 70.)
(C) There were no reports on Form 8-K filed during the last quarter of 2001
and the 2002 period covered by this report under Item 5.
60
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
SCHEDULE II
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Schedule II -- Valuation and Qualifying Accounts
Years Ended December 31, 2001 -- December 31, 1999
Column B Column C Column D Column E
------------- ---------------------------- --------------- -------------
Additions
----------------------------
Balance at Charged to Charged to Balance at
beginning of cost and other Deductions- end of
accounts-
Description Period expenses describe describe Period
- ------------------------------------------- ------------- ---------------------------- --------------- -------------
(Millions of Dollars)
2001:
Allowance for Doubtful Accounts.......... $39 $45 $-- $46(A) $38
2000:
Allowance for Doubtful Accounts.......... $35 $45 $-- $41(A) $39
Materials and Supplies Valuation Reserve. 11 -- -- 11(D) --
1999:
Allowance for Doubtful Accounts.......... $34 $40 $-- $39(A) $35
Discount on Property Abandonments........ 1 -- -- 1(B) --
Materials and Supplies Valuation Reserve. 12 41 -- 42(C) 11
(A) Accounts Receivable/Investments written off.
(B) Amortization of discount to income.
(C) Inventory written off.
(D) Transferred to Power.
61
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: March 7, 2002
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 Chief March 7, 2002
- -----------------------------------------------
E. James Ferland Executive Officer and Director
(Principal Executive Officer)
ALFRED C. KOEPPE President and Chief Operating Officer March 7, 2002
- -----------------------------------------------
Alfred C. Koeppe
ROBERT E. BUSCH Senior Vice President - Finance and Chief March 7, 2002
- -----------------------------------------------
Robert E. Busch Financial Officer (Principal Financial Officer)
PATRICIA A. RADO Vice President and Controller March 7, 2002
- -----------------------------------------------
Patricia A. Rado (Principal Accounting Officer)
ALBERT R. GAMPER, JR. Director March 7, 2002
- -----------------------------------------------
Albert R. Gamper, Jr.
CONRAD K. HARPER Director March 7, 2002
- -----------------------------------------------
Conrad K. Harper
MARILYN M. PFALTZ Director March 7, 2002
- -----------------------------------------------
Marilyn M. Pfaltz
62
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. 001-00973.
(b) Filed by PSE&G with Form 8-K under the Securities Exchange Act of 1934, on
the respective dates indicated, File No. 001-00973.
(c) Filed by PSE&G with Form 10-K under the Securities Exchange Act of 1934, on
the respective dates indicated, File No. 001-00973.
(d) Filed by PSE&G with Form 10-Q under the Securities Exchange Act of 1934, on
the respective dates indicated, File No. 001-00973.
(e) Filed by PSEG with Form 10-K under the Securities Exchange Act of 1934, on
the respective dates indicated, File No. 001-09120.
(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.
(q) Filed with registration statement of PSE&G under the Securities Act of
1933, No. 333-76020, effective February 12, 2002, relating to the
registration of $1,000,000,000 of Senior Debt Securities.
63
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
PSE&G
- ----------------------------------------------------
Exhibit Number
- ----------------------------------------------------
This Previous Filing
---------------------------------------
Filing Commission Exchanges
------ ---------- ---------
3a(1) (b) 3a (b) 3a Restated Certificate of Incorporation of PSE&G
8/28/86 8/29/86
3a(2) (c) 3a(2) (c) 3a(2) Certificate of Amendment of Certificate of Restated
4/10/87 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 of
2/3/94 2/14/94 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 of
2/3/94 2/14/94 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 of
2/3/94 2/14/94 Incorporation of PSE&G filed January 27, 1995 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(1) (d) (d) Copy of By-Laws of PSE&G
8/8/00 8/8/00
4a(1) (f) B-1 (c) 4b(1) Indenture between PSE&G and Fidelity Union Trust
2/18/81 Company, (now First Union National Bank, National
Association), as Trustee, dated August 1, 1924,
securing First and Refunding Mortgage Bond
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
64
PSE&G
- ----------------------------------------------------
Exhibit Number
- ----------------------------------------------------
This Previous Filing
---------------------------------------
Filing Commission Exchanges
------ ---------- ---------
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
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
65
PSE&G
- ----------------------------------------------------
Exhibit Number
- ----------------------------------------------------
This Previous Filing
---------------------------------------
Filing Commission Exchanges
------ ---------- ---------
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
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
66
PSE&G
- ----------------------------------------------------
Exhibit Number
- ----------------------------------------------------
This Previous Filing
---------------------------------------
Filing Commission Exchanges
------ ---------- ---------
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
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
67
PSE&G
- ----------------------------------------------------
Exhibit Number
- ----------------------------------------------------
This Previous Filing
---------------------------------------
Filing Commission Exchanges
------ ---------- ---------
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
4a(82) (a) 4 (a) 4 September 1, 1993 (No. 2)
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
68
PSE&G
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Exhibit Number
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This Previous Filing
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Filing Commission Exchanges
------ ---------- ---------
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
4a(94) (c) 4 December 1, 1996
2/26/97
4a(95) (a) 4 (a) 4 June 1, 1997
6/17/97 6/17/97
4a(96) (a) 4 (a) 4 May 1, 1998
5/15/98 5/15/98
4b (b) 4 (b) 4 Indenture of Trust between PSE&G and Chase
12/1/93 12/1/93 Manhattan Bank (National Association), as Trustee,
providing for Secured Medium-Term Notes dated July
1, 1993
4c(1) (b) (c) Indenture between PSE&G and First Fidelity Bank,
2/23/95 2/23/95 National Association (now known as First Union
National Bank), as Trustee, dated November 1, 1994,
providing for Deferrable Interest Subordinated
Debentures in Series
4c(2) (a) 4b(5) (a) 4b(5) Supplemental Indenture between PSE&G and First
Fidelity Bank, National Association (now known as
(d) 4d(2) (d) 4d(2) First Union National Bank), as Trustee, dated
5/13/98 5/13/98 September 1, 1995 providing for Deferrable Interest
Subordinated Debentures, Series B (relating to
Monthly Preferred Securities)
4d(1) (d) 4e(1) (d) 4e(1) Indenture between PSE&G and First Union National
5/13/98 5/13/98 Bank, as Trustee, dated June 1, 1996 providing for
Deferrable Interest Subordinated Debentures in
Series (relating to Quarterly Preferred Securities)
4d(2) (d) 4e(2) (d) 4e(2) Supplemental Indenture between PSE&G and First Union
5/13/98 5/13/98 National Bank, as Trustee, dated February 1, 1997
providing for Deferrable Interest Subordinated
Debentures, Series B (relating to Quarterly
Preferred Securities)
4e (q) 4-6 (q) 4-6 Indenture dated as of December 1, 2000 between Public
2/12/02 2/12/02 Service Electric and Gas Company and First Union
National Bank, as Trustee, providing for Senior Debt
Securities.
Senior Note Indenture
69
PSE&G
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Exhibit Number
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This Previous Filing
---------------------------------------
Filing Commission Exchanges
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10a(1) (c) 10a(1) (c) 10a(1) Directors' Deferred Compensation Plan
2/25/00 2/25/00
10a(2) (c) 10a(2) (c) 10a(2) Deferred Compensation Plan for Certain Employees
2/25/00 2/25/00
10a(3) (c) 10a(3) (c) 10a(3) Limited Supplemental Benefits Plan for Certain
Employees
2/25/00 2/25/00
10a(4) (c) 10a(4) (c) 10a(4) Mid Career Hire Supplemental Retirement Plan
2/25/00 2/25/00
10a(5) (c) 10a(5) (c) 10a(5) Retirement Income Reinstatement Plan
2/25/00 2/25/00
10a(6) (c) 10a(6) (c) 10a(6) 1989 Long-Term Incentive Plan
2/22/99 2/22/99
10a(7) (c) 10a(7) (c) 10a(7) 2001 Long-Term Incentive Plan
3/5/01 3/5/01
10a(8) (c) 10a(8) 10a(8) Restated and Amended Management Incentive
Compensation Plan
3/5/01 3/5/01
10a(9) (d) 10 (d) 10 Employment Agreement with E. James Ferland, dated
8/14/98 8/14/98 June 16, 1998
10a(10) (c) 10a(13) (c) 10a(13) Letter Agreement with Patricia A. Rado dated
2/26/94 3/9/94 March 24, 1993
10a(11) (d) 10a(21) (d) Employment Agreement with Alfred C. Koeppe dated
11/13/00 October 17, 2000
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
23 Independent Auditors' Consent