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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2002
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
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
As of June 30, 2002, Public Service Electric and Gas Company and 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.
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
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TABLE OF CONTENTS
PAGE
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PART I. FINANCIAL INFORMATION
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Item 1. Financial Statements........................................... 1
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................... 11
Item 3. Qualitative and Quantitative Disclosures About Market Risk..... 17
PART II. OTHER INFORMATION
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Item 1. Legal Proceedings......................................... 19
Item 5. Other Information......................................... 19
Item 6. Exhibits and Reports on Form 8-K.......................... 21
Signature............................................................... 22
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
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PART I. FINANCIAL INFORMATION
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ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars)
(Unaudited)
For the Quarters Ended For the Six Months Ended
June 30, June 30,
----------------------------- ------------------------------
2002 2001 2002 2001
----------- ------------- ------------ -------------
OPERATING REVENUES
Electric Transmission and Distribution................... 924 959 $ 1,768 $ 1,829
Gas Distribution......................................... 306 352 1,121 1,434
----------- ------------- ------------ -------------
Total Operating Revenues............................. 1,230 1,311 2,889 3,263
----------- ------------- ------------ -------------
OPERATING EXPENSES
Electric Energy Costs.................................... 569 558 1,101 1,111
Gas Costs................................................ 189 243 716 1,030
Operation and Maintenance................................ 233 242 482 492
Depreciation and Amortization............................ 100 91 198 163
Taxes Other than Income Taxes............................ 32 31 75 74
----------- ------------- ------------ -------------
Total Operating Expenses............................. 1,123 1,165 2,572 2,870
----------- ------------- ------------ -------------
OPERATING INCOME 107 146 317 393
Other Income................................................ 6 24 11 94
Other Deductions............................................ (1) (1) (2)
Interest Expense............................................ (102) (112) (203) (228)
Preferred Securities Dividend Requirements of Subsidiaries.. (4) (7) (7) (18)
----------- ------------- ------------ -------------
INCOME BEFORE INCOME TAXES.................................. 7 50 117 239
Income Taxes................................................ 1 (18) (41) (95)
----------- ------------- ------------ -------------
NET INCOME.................................................. 8 32 76 144
Preferred Securities Dividend Requirements and Premium
on Redemption............................................ (1) (1) (2) (4)
----------- ------------- ------------ -------------
EARNINGS AVAILABLE TO PUBLIC SERVICE
ENTERPRISE GROUP INCORPORATED............................ $ 7 $ 31 $ 74 $ 140
=========== ============= ============ =============
See Notes to Consolidated Financial Statements
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
(Unaudited)
June 30, December 31,
2002 2001
--------------- ----------------
CURRENT ASSETS
Cash and Cash Equivalents............................................... 191 $ 102
Accounts Receivable:
Customer Accounts Receivable.......................................... 505 556
Other Accounts Receivable............................................. 55 67
Allowance for Doubtful Accounts....................................... (32) (38)
Unbilled Revenues....................................................... 181 291
Natural Gas............................................................. -- 415
Materials and Supplies.................................................. 56 50
Prepayments............................................................. 275 40
Energy Contracts........................................................ -- 32
Restricted Cash......................................................... 13 12
Other................................................................... 23 22
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Total Current Assets.................................................. 1,267 1,549
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PROPERTY, PLANT AND EQUIPMENT
Electric................................................................ 5,604 5,501
Gas .................................................................... 3,355 3,284
Other................................................................... 390 385
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Total................................................................. 9,349 9,170
Accumulated Depreciation and Amortization............................... (3,478) (3,329)
--------------- ----------------
Net Property, Plant and Equipment..................................... 5,871 5,841
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NONCURRENT ASSETS
Regulatory Assets....................................................... 5,094 5,247
Long-Term Investments................................................... 118 112
Other Special Funds..................................................... 172 130
Other................................................................... 75 84
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Total Noncurrent Assets............................................... 5,459 5,573
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TOTAL ASSETS............................................................... 12,597 12,963
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See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions of Dollars)
(Unaudited)
June 30, December 31,
2002 2001
--------------- ----------------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year..................................... 974 668
Accounts Payable....................................................... 504 642
Energy Contracts....................................................... -- 169
Accrued Taxes.......................................................... 37 30
Other.................................................................. 298 277
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Total Current Liabilities............................................ 1,813 1,786
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NONCURRENT LIABILITIES
Deferred Income Taxes and ITC.......................................... 2,542 2,551
Regulatory Liabilities................................................. 409 373
OPEB Costs............................................................. 483 466
Other.................................................................. 202 205
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Total Noncurrent Liabilities......................................... 3,636 3,595
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CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt....................................................... 2,327 2,626
Securitization Debt.................................................. 2,293 2,351
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Total Long-Term Debt............................................... 4,620 4,977
PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption......................... 80 80
Subsidiaries' Preferred Securities:
Guaranteed Preferred Beneficial Interest in Subordinated
Debentures......................................................... 155 155
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Total Preferred Securities......................................... 235 235
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COMMON STOCKHOLDER'S EQUITY
Common Stock, 150,000,000 shares authorized, 132,450,344
shares issued and outstanding...................................... 892 892
Basis Adjustment..................................................... 986 986
Retained Earnings.................................................... 417 493
Accumulated Other Comprehensive Loss................................. (2) (1)
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Total Common Stockholder's Equity.................................. 2,293 2,370
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Total Capitalization............................................. 7,148 7,582
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TOTAL LIABILITIES AND CAPITALIZATION...................................... 12,597 12,963
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See Notes to Consolidated Financial Statements
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
For the Six Months Ended
June 30,
-------------------------------------
2002 2001
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CASH FLOWS FROM OPERATING ACTIVITIES
Net income................................................................. $ 76 $ 144
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization.............................................. 198 163
Amortization of Deferred Gas Costs......................................... 17 --
Provision for Deferred Income Taxes and ITC................................ (26) 21
Other Non-Cash Charges..................................................... 15 19
Net Changes in Certain Current Assets and Liabilities:
Accounts Receivable and Unbilled Revenues................................ 167 206
Natural Gas.............................................................. 415 18
Prepayments.............................................................. (235) (228)
Restricted Cash.......................................................... (1) (62)
Accounts Payable......................................................... (138) (206)
Accrued Taxes............................................................ 7 (4)
Other Current Assets and Liabilities..................................... -- 57
Overrecovery of Electric Energy Costs and Market Transition Charge (MTC)... 93 13
Underrecovery of Gas Costs................................................. (92) (111)
Other...................................................................... 54 14
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Net Cash Provided By Operating Activities................................ 550 44
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CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment................................. (196) (172)
Contributions to Other Special Funds....................................... (63) (30)
Other...................................................................... 1 (6)
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Net Cash Used in Investing Activities.................................... (258) (208)
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CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt.............................................. -- (1,487)
Issuance of Long-Term Debt................................................. -- 2,525
Deferred Issuance Costs.................................................... -- (201)
Redemption/Purchase of Long-Term Debt...................................... (51) (299)
Collection of Note Receivable - Affiliated Company......................... -- 2,786
Redemption of Preferred Securities......................................... -- (448)
Return of Capital.......................................................... -- (2,265)
Cash Dividends Paid on Common Stock........................................ (150) (112)
Other...................................................................... (2) (4)
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Net Cash Provided By (Used) in Financing Activities...................... (203) 495
-------------- ------------------
Net Change in Cash and Cash Equivalents....................................... 89 331
Cash and Cash Equivalents at Beginning of Period.............................. 102 39
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Cash and Cash Equivalents at End of Period.................................... 191 $ 370
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Income Taxes Paid............................................................. 117 $ 192
Interest Paid................................................................. 202 $ 152
See Notes to Consolidated Financial Statements
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 1. Organization and Basis of Presentation
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 and its consolidated subsidiaries. We are a wholly-owned subsidiary
of Public Service Enterprise Group Incorporated (PSEG) and are an operating
public utility providing electric transmission and electric and gas distribution
service in certain areas within the State of New Jersey. PSEG owns all of our
common stock.
Basis of Presentation
The financial statements included herein have been prepared pursuant to the
rules and regulations of the Securities and Exchange Commission (SEC). Certain
information and note disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted pursuant to such rules and regulations. However, in the
opinion of management, the disclosures are adequate to make the information
presented not misleading. These Consolidated Financial Statements (Statements)
and Notes to Consolidated Financial Statements (Notes) update and supplement
matters discussed in our 2001 Annual Report on Form 10-K and should be read in
conjunction with those Notes.
The unaudited financial information furnished reflects all adjustments which
are, in the opinion of management, necessary to fairly state the results for the
interim periods presented. The year-end Consolidated Balance Sheets were derived
from the audited Consolidated Financial Statements included in our 2001 Annual
Report on Form 10-K. Certain reclassifications of prior period data have been
made to conform with the current presentation.
Note 2. Accounting Matters
On January 1, 2002, we adopted Statement of Financial Accounting Standards
(SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142). Under SFAS
142, goodwill is considered a nonamortizable asset and is subject to an annual
review for impairment and an interim review when required by events or
circumstances. We currently do not have any goodwill or other intangible assets
on our balance sheet. Therefore, there was no effect on our financial position
or results of operations as a result of adopting this standard.
On January 1, 2002 we adopted SFAS 144. On adoption, the impact of SFAS 144 did
not have an effect on our financial position or results of operations. Under
SFAS 144, long-lived assets to be disposed of are measured at the lower of
carrying amount or fair value less costs to sell, whether reported in continued
operations or in discontinued operations. Also under SFAS 144, discontinued
operations will no longer be measured at net realizable value or include amounts
for operating losses that have not yet occurred. Under SFAS 144, discontinued
operations will be measured at fair value, less costs to sell. Also, as under
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" (SFAS 121), a long-lived asset must be tested for
impairment whenever events or changes in circumstances indicate that its
carrying amount may be impaired.
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No.
143, "Accounting for Asset Retirement Obligations" (SFAS 143). Under SFAS 143,
the fair value of a liability for an asset retirement obligation should be
recorded in the period in which it is created with an offsetting amount to an
asset. 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 may be
material to the classification of items on our balance sheet. We currently do
not expect any income statement effect due to the adoption of this statement.
Note 3. Regulatory Assets and Liabilities
We prepare our financial statements in accordance with the provisions of SFAS
71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) which
differs in certain respects from the application of 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 utility 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. These costs are
deferred based on rate orders issued by the New Jersey Board of Public Utilities
(BPU) or the Federal Energy Regulatory Commission (FERC) and our recovery
experience with prior rate cases. As of June 30, 2002, approximately 87% of our
regulatory assets were deferred based on written rate orders. Regulatory assets
recorded on a basis other than by an issued rate order have less certainty of
recovery since they can be disallowed in the future by regulatory authorities.
However, we have experienced no material disallowances in the past. We believe
that all of our regulatory assets are probable of recovery.
At June 30, 2002 and December 31, 2001, respectively, we had deferred the
following regulatory assets and liabilities on the Consolidated Balance Sheets:
June 30, December 31,
2002 2001
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(Millions of Dollars)
Regulatory Assets
Stranded Costs To Be Recovered.................................. $4,009 $4,105
SFAS 109 Income Taxes........................................... 313 302
OPEB Costs...................................................... 203 212
Societal Benefits Charges (SBC)................................. -- 4
Manufactured Gas Plant Remediation Costs........................ 87 87
Unamortized Loss on Reacquired Debt and Debt Expense............ 88 92
Underrecovered Gas Costs........................................ 195 120
Unrealized Losses on Gas Contracts.............................. -- 137
Other........................................................... 199 188
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Total Regulatory Assets................................... $5,094 $5,247
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Regulatory Liabilities
Excess Depreciation Reserve..................................... $245 $319
Non-Utility Generation Transition Charge (NTC).................. 125 48
SBC............................................................. 28 --
Other........................................................... 11 6
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Total Regulatory Liabilities.............................. $409 $373
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All regulatory assets and liabilities are excluded from our rate base unless
otherwise noted in the descriptions below.
Stranded Costs To Be Recovered: This reflects the deferred costs to be recovered
by the securitization transition charge, which was authorized by the BPU's Final
Order and Finance Order in our deregulation proceedings. These orders are a
matter of public record and are available at the BPU. These costs primarily
relate to the write-down of our fixed assets in 1999 that was required under
SFAS No. 121, "Accounting for Long-Lived Assets and Long-Lived Assets to be
Disposed of" (SFAS 121). PSE&G Transition Funding LLC (Transition Funding), our
wholly-owned subsidiary, issued transition bonds to recover these costs net of
deferred taxes. Accordingly, this regulatory asset is offset by securitization
debt and a deferred tax liability. Funds collected through the securitization
transition charge will be used to make the future interest and principle
payments on the transition bonds. This amount will be recovered over the life of
the transition bonds, which is expected to conclude in December 2015.
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. Accordingly,
this regulatory asset is offset by a deferred tax liability and is expected to
be recovered without interest over the period the underlying book-tax timing
differences reverse and become current taxes.
OPEB Costs: Includes costs associated with adoption of SFAS No. 106, "Employers'
Accounting for Benefits Other Than Pensions" (SFAS 106), which were deferred in
accordance with EITF Issue 92-12, "Accounting for OPEB Costs by Rate Regulated
Enterprises" (EITF 92-12). 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 began to recover this
regulatory asset over 15 years without interest.
SBC: The SBC includes costs related to our electric and gas 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 expenditures; 5) consumer
education; 6) Under and overrecovered electric bad debt expenses; and 7) MTC
overrecovery. These costs are recovered/refunded with interest. The SBC clause
will be revised at the end of the transition period on August 1, 2003.
Manufactured Gas Plant Remediation Costs: Represents estimated future
environmental investigation and remediation expenditures (net of insurance
recoveries), which are probable of recovery in future rates through the SBC.
This amount will be transferred to the SBC regulatory asset when the actual
expenditures are made. Interest is not recoverable on these costs until the
actual expenditures are made. This regulatory asset is offset by a noncurrent
liability on the balance sheet.
Unamortized Loss on Reacquired Debt and Debt Expense: Represents bond issuance
costs, premiums, discounts and losses on reacquired long-term debt. These costs
are amortized with interest, over the remaining life of the reacquired debt or
over the life of the new debt, if refinanced.
Underrecovered Gas Costs: Represents gas costs in excess of or below the amount
included in rates and probable of recovery in the future. Generally,
underrecovered gas costs do not accrue interest while overrecovered gas costs do
accrue interest. The LGAC rate is normally adjusted on an annual basis. A
portion of the current underrecovery, $117 million at June 30, 2002, is being
recovered over an extended period through September 2004. We are recovering
interest during this extended period. The remaining portion of the current
underrecovery, $78 million, is expected to be recovered subsequent to our next
gas rate proceeding, the time of which is not currently known.
Unrealized Losses on Gas Contracts: This represents the recoverable portion of
unrealized losses associated with contracts used in the company's gas
distribution business. This asset is offset by the net energy contracts payable
on the balance sheet. Subsequent to the gas contract transfer to PSEG Power LLC
(Power), an unregulated affiliate, in May 2002, we no longer enter into these
contracts.
Other Regulatory Assets: Includes Decontamination and Decommissioning Costs
which are offset by a noncurrent liability on the balance sheet and are expected
to be collected without interest until December 2007; Plant and Regulatory Study
Costs are expected to be recovered without interest until December 2021; Repair
Allowance Tax Deficiencies and Interest; Oil and Gas Property Write-Down which
is expected to be recovered without interest until December 2002; restructuring
costs that will be recovered with or without interest, which will be determined
at our upcoming electric rate case, from August 1, 2003 through July 31, 2007
and recovery of costs related to Transition Funding's interest rate swap that
will be recovered without interest over the life of Transition Funding's
transition bonds, which is expected to conclude in December 2015. This asset is
offset by a derivative liability on the balance sheet.
Excess Depreciation Reserve: As required by a BPU rate order, 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.
NTC: This clause was established to account for above market costs related to
non-utility generation (NUG) contracts. NUG contract costs are charged to
expense and proceeds from the sale of the energy and capacity purchased under
these NUG contracts are also credited to expense. The difference between the
collection of NTC revenue and the related expense is deferred. Costs or benefits
associated with the restructuring of these contracts are deferred as well. These
amounts are expected to be returned to customers with interest. The NTC clause
will be revised at the end of the transition period on August 1, 2003. The NTC
balance, including the anticipated deferral of the difference between the Basic
Generation Service (BGS) payments to suppliers and collections from customers,
are expected to be addressed together with the new electric distribution base
rates and incorporated into rates on August 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 from customers
resulting from the Energy Tax Reform Act that are currently being used to fund
customer education discounts approved by the BPU; 3) Amounts collected from
customers in order for Transition Funding to obtain a AAA rating on its
transition bonds and 4) Amounts that will be returned to Firm Gas customers with
interest.
Note 4. 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 our 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 the
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 (MGPs). 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 at
least $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.
At June 30, 2002 and December 31, 2001, our estimated liability for remediation
costs through 2004 aggregated $87 million. Expenditures beyond 2004 cannot be
reasonably 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 in the Passaic River "facility." We and certain of our predecessors
conducted industrial operations at properties on that six mile stretch of the
Passaic River. The operations include one operating electric generating station,
one former generating station, and four former MGPs. Our costs to clean up
former MGPs are recoverable from utility customers under the SBC. We have
contracted to sell the site of the former generating station, contingent upon
approval by state regulatory agencies, to a third party that would release and
indemnify us for claims arising out of the site. We cannot predict what action,
if any, the EPA or any third party may take against us with respect to this
matter, or in such event, what costs we may incur to address any such claims.
However, such costs may be material.
Note 5. 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 June 30, 2002 and December 31, 2001, respectively.
June 30, 2002 December 31, 2001
------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ ----------- ------------ -----------
(Millions of Dollars)
Long-Term Debt:
PSE&G................................................. $3,301 $3,351 $3,294 $3,290
Transition Funding.................................... 2,293 2,536 2,351 2,575
Preferred Securities Subject to Mandatory Redemption:
Monthly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 60 61 60 60
Quarterly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 95 96 95 96
Commodity-Related Instruments
Prior to May 1, 2002, we used natural gas futures and swaps to reduce exposure
to price fluctuations in natural gas 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, were designed to cover estimated gas customer commitments. We had
entered into 330 MMBTU of gas futures, swaps and options to hedge forecasted
requirements as of December 31, 2001. As of December 31, 2001, the fair value of
those instruments was $(137) million, with a maximum term of approximately one
year. We utilized derivatives to hedge our gas purchasing activities which, when
realized, were recoverable through our Levelized Gas Adjustment Clause (LGAC).
Accordingly, the offset to the change in fair value of these derivatives was
recorded as a regulatory asset or liability.
As a result of the gas contract transfer that was effective May 1, 2002, the
price risk relating to gas purchases was transferred to Power. As a result,
after that date, we are no longer utilizing these derivative instruments in our
gas distribution business. Our gas supply is now obtained through the Basic Gas
Supply Service (BGS) contract with Power. See Note 10. Related Party
Transactions for further discussion.
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. We currently have no
floating rate debt outstanding that is exposed to interest rate risk.
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
was 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 $(32) million as of June 30, 2002 and $(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.
Note 6. Income Taxes
A tax (benefit) expense has been recorded for the results of continuing
operations. An analysis of that (benefit) expense is as follows:
Quarter Ended Six Months Ended
June 30, June 30,
------------------------- ------------------------
2002 2001 2002 2001
----------- ---------- ----------- ---------
Pre-Tax Income........................................... $7 $ 50 $117 $239
Tax Computed at the Federal Statutory Rate at 35%........ 2 18 41 84
Increases (decreases) from Federal statutory rate
attributable to:
State Income Taxes after Federal Benefit............. 1 4 10 18
Plant Related Items.................................. (3) (5) (7) (10)
Other................................................ (1) 1 (3) 3
----------- ---------- ------------ ---------
Total Income Tax Expense................................. $(1) $18 $41 $95
----------- ---------- ------------ ---------
Effective Income Tax Rate.......................... (14.3%) 36.0% 35.0% 39.7%
For the quarter ended June 30, 2002, regulatory accounting differences,
primarily plant-related items, are proportionally higher relative to pre-tax
income resulting in a relatively low effective tax rate.
Note 7. Financial Information by Business Segments
Following the transfer of our generation-related assets to Power in August 2000,
we continue to own and operate our transmission and distribution (T&D) business
as our only reportable segment.
Note 8. Comprehensive Income
Comprehensive Income, Net of Tax:
Quarter Ended Six Months Ended
June 30, June 30,
------------------------ -----------------------
2002 2001 2002 2001
--------- ---------- --------- ----------
Net Income.................................................... $8 $32 $76 $144
Pension Adjustment, Net of Tax................................ -- 2 (1) 2
--------- ---------- --------- ----------
Comprehensive Income.......................................... $8 $34 $75 $146
========= ========== ========= ==========
Note 9. Other Income
Quarter Ended Six Months Ended
June 30, June 30,
---------------------- -----------------------
2002 2001 2002 2001
--------- -------- --------- ----------
(Millions of Dollars)
Other Income
Interest Income........................................... $5 $21 $9 $90
Gain on Disposition of Property........................... 1 3 1 3
Other..................................................... -- -- 1 1
--------- -------- --------- ----------
Total Other Income............................................ $6 $24 $11 $94
========= ======== ========= ==========
Note 10. Related-Party Transactions
In August 2000, we transferred our electric generation business 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 $6 million and $33 million
relating to the loan for the quarter and six months ended June 30, 2001
respectively. 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 BPU's Final Order, as part of our recapitalization.
Effective with the transfer of the electric generation business, Power charges
us for the Market Transition Charge (MTC) and the energy and capacity provided
to meet our BGS requirements. 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. The amounts we
recover from customers through the MTC are paid to Power, thus this does not
impact our earnings. For the quarters ended June 30, 2002 and 2001, we were
charged by Power approximately $488 million and $475 million, respectively, for
the MTC and BGS. For the six months ended June 30, 2002 and 2001, we were
charged by Power approximately $948 million and $938 million, respectively, for
the MTC and BGS. As of June 30, 2002 and December 31, 2001, our payable to Power
relating to these costs was approximately $179 million and $159 million. For the
quarters ended June 30, 2002 and 2001, respectively, we sold energy and capacity
to Power at the market price of approximately $34 million and $36 million, which
we purchased under various NUG contracts at costs above market prices. For the
six months ended June 30, 2002 and 2001, these sales totaled $63 million and $80
million, respectively. As of June 30, 2002 and December 31, 2001, our receivable
related to these purchases was approximately $13 million and $7 million,
respectively. As a result of the Final Order, we have established a 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 PJM for energy
and at wholesale market prices for capacity, is deferred as a regulatory asset
or liability.
Effective May 1, 2002, we transferred our gas supply contracts and gas inventory
to Power for approximately $183 million. On the same date we entered into a
requirements contract with Power under which Power will provide the delivered
gas supply services needed to meet our BGSS. The contract term ends March 31,
2004 with a three-year renewal option. As part of the agreement, we are
providing Power the use of our peaking shaving facilities at cost. The net
billings under the contract for the quarter ended June 30, 2002 were
approximately $96 million. Our net payable as of June 30, 2002 was approximately
$54 million.
PSEG Services Corporation provides and bills administrative services to us on a
monthly basis. Our costs related to such service amounted to approximately $51
million and $61 million for the quarters ended June 30, 2002 and 2001,
respectively. These costs totaled $103 million and $116 million for the six
months ended June 30, 2002 and 2001, respectively. As of June 30, 2002 and
December 31, 2001, our payable related to these costs was approximately $19
million and $25 million, respectively.
================================================================================
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
================================================================================
ITEM 2. 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.
Following are the significant changes in or additions to information reported in
our 2001 Annual Report on Form 10-K and March 31, 2002 Quarterly Report on Form
10-Q affecting the consolidated financial condition and the results of
operations of our subsidiaries and us. This discussion refers to our
Consolidated Financial Statements (Statements) and related Notes to Consolidated
Financial Statements (Notes) and should be read in conjunction with such
Statements and Notes.
Overview of the Quarter and Six Months Ended June 30, 2002 and Future Outlook
For the quarter ended June 30, 2002, net income decreased $24 million or 75% as
compared to the quarter ended June 30, 2001 primarily due to lower electric
revenue and interest income compared to the prior period, partially offset by
increased gas base rates and lower interest and income tax expense due to lower
pre-tax income. The lower electric revenue that impacted earnings primarily
related to demand side management (DSM), distribution sales volumes and
miscellaneous revenues. For further discussion, see the Results of Operation
section.
For the six months ended June 30, 2002, net income decreased $68 million or 47%
as compared to the six months ended June 30, 2001 primarily due to lower gas
sales volumes as a result of the warmer weather in early 2002, lower electric
revenue and interest income compared to the prior period. This was partially
offset by increased gas base rates and lower interest and income tax expense due
to lower pre-tax income. The lower electric revenue that impacted earnings
primarily related to DSM, distribution sales volumes and miscellaneous revenues.
For further discussion, see the Results of Operation section.
Our cash position increased $89 million from December 31, 2001 to June 30, 2002
due primarily to $550 million of operating cash inflows offset by $258 million
and $203 million of cash outflows for investing and financing activities,
respectively. Our operating cash inflows were primarily due to the gas contract
transfer to Power, the restructuring of our non-utility generation (NUG)
contract with El Paso Merchant Energy, and cash earnings during the period
offset by prepayments of taxes. Our investing cash outflows related primarily to
construction expenditures. Our financing cash outflows related primarily to the
redemption of the Class A-1 series of PSE&G Transition Funding LLC's (Transition
Funding) transition bonds and cash dividends paid on common and preferred stock.
On June 5, 2002 we amended our NUG contract with El Paso Merchant Energy. Under
federal law, we and other utilities were required to enter into long-term NUG
contracts with cogeneration facilities. We sell the electricity we purchase
under these contracts to Power at the Locational Marginal Price (LMP) in the
Pennsylvania-New Jersey-Maryland Power Pool (PJM). Any difference between the
amounts we pay under the NUG Contracts and the amount we recover through the
Non-Utility Generation Transition Charge (NTC) and sales at LMP are deferred as
a regulatory asset or liability. Under the amended contract, we received $102
million in return for allowing El Paso Merchant Energy to provide electric
energy and capacity from the open market, in addition to their existing plant.
This amount will be passed back to customers through the NTC and was recorded as
a regulatory liability.
Effective May 1, 2002 we transferred our gas supply contracts and gas inventory
to Power for approximately $183 million. We received $149 million in cash and
Power assumed $34 million of liabilities relating to our commodity contracts. On
the same date, we entered into a requirements contract with Power under which
Power will provide the delivered gas supply services needed to meet our Basic
Gas Supply Service (BGSS). The contract term ends March 31, 2004 with a
three-year renewal option. As part of the agreement, we are providing Power the
use of our peaking shaving facilities at cost.
Under the terms of the contract, Power provides gas for Commercial and
Industrial BGSS customers at market based pricing which is passed on directly to
the customers. Gas for Residential BGSS customers is priced at Power's cost,
which includes the cost of any hedging arrangements. We defer the difference
between that cost and the amount included in customer rates for future recovery
or return under our Levelized Gas Adjustment Charge (LGAC).
On May 1, 2002, the New Jersey Ratepayer Advocate filed a motion for the
reconsideration of the BPU's approval of the gas contract transfer. We have
opposed this motion and this matter is currently pending before the BPU.
For the quarter and six month ended June 30, 2002, we deferred approximately $8
million and $16 million of revenues, respectively, due to overcollections from
the Market Transition Charge (MTC). These amounts will be refunded to customers
with interest through the societal benefits charge (SBC) beginning August 1,
2003. Refer to the Critical Accounting Policies section for additional
information regarding the MTC.
On May 24, 2002, we filed an electric rate case with the New Jersey Board of
Public Utilities (BPU). In this filing, we requested an annual $250 million rate
increase for our electric distribution business. The proposed rate increase
includes $187 million of increased revenues relating to a $1.7 billion increase
in our rate base, which is primarily due to the investment that we have made in
our electric distribution facilities since the last electric rate case in 1992;
$18 million in higher depreciation rates and $45 million to recover various
other expenses, such as wages, fringe benefits, and the need to enhance the
security and reliability of the electric distribution system. The requested
increase proposes a maximum return on equity of 11.75% for our electric
distribution business.
Assuming current cost levels and a normal business environment, the proposed
rate increase would significantly impact our earnings and operating cash flows.
The non-depreciation portion of the rate increase ($232 million) would have a
positive effect on our earnings and operating cash flows. The depreciation
portion of the rate increase ($18 million) would have no impact on our earnings,
as the increased operating cash flows would be offset by higher depreciation
charges.
In accordance with BPU'S Final Order, which implemented parts of New Jersey's
Electric Discount and Competition Act, we were required to reduce electric rates
in four steps totaling 13.9% during the four year transition period. The last
step, a 4.9% decrease, will take effect August 1, 2002.
If approved, the proposed rate increase would be effective August 1, 2003, the
end of the transition period. While the proposed rate increase would increase
electric distribution rates by 12.8% from the July 31, 2003 level, rates will
remain 2.6% lower than the levels in April 1999, when the BPU issued its Final
Order. We cannot predict the outcome of these rate proceedings at the current
time.
Various cost-cutting initiatives recently put in place are expected to offset
lower revenues from our gas distribution business due to the warmer weather in
2002, and as a result, we have affirmed our projected earnings for the year. We
currently expect to earn between $175 million to $185 million for the twelve
months ending December 31, 2002. Our future success will be dependent, in part,
on our ability to obtain a successful outcome to the recently filed electric
rate case, our ability to continue to recover the regulatory assets we have
deferred, the investments we plan to make in our electric and gas transmission
and distribution systems. We will also be impacted by the effect of lower
assumed rate of returns and lower fund balances on our pension and other
postretirement benefit plan (OPEB) expenses.
RESULTS OF OPERATIONS
Operating Revenues
Electric Transmission and Distribution
Electric Transmission and Distribution revenues decreased $35 million or 4% for
the quarter ended June 30, 2002 as compared to the quarter ended June 30, 2001
primarily due to the implementation of a 2% electric rate reduction in August of
2001, lower DSM revenues, lower distribution sales volumes and a decrease in
miscellaneous revenues offset by increased commodity sales volumes. The 2% rate
reduction reduced revenues by approximately $18 million and is passed through to
Power through a reduction in the MTC. As a result, electric energy costs
decreased by a corresponding amount. Revenues also decreased by approximately
$19 million due to lower recovery of lost sales associated with DSM programs
through the SBC. Also, lower distribution sales volumes, primarily relating to
our industrial customers, reduced revenues by approximately $6 million. Finally,
there was an approximate $12 million decrease in miscellaneous electric revenues
primarily relating to replacement capacity charges (approximately $8 million)
and fiber optics (approximately $2 million). Partially offsetting these
decreases were higher Basic Generation Service (BGS) or commodity sales volumes,
which increased revenues by approximately $22 million and was primarily due to
customers returning to us from third party suppliers (TPS) as wholesale market
prices exceeded the fixed BGS rates. At June 30, 2002, TPS were serving 0.3% of
the customer load traditionally served by us as compared to the June 30, 2001
level of 1.5%.
Electric Transmission and Distribution revenues decreased $61 million or 3% for
the six months ended June 30, 2002 as compared to the six months ended June 30,
2001 primarily due to the implementation of a 2% electric rate reduction in
February of 2001 and another 2% electric rate reduction in August of 2001, lower
DSM revenues, lower distribution sales volumes and a decrease in miscellaneous
revenues offset by increased commodity sales volumes. The electric rate
reductions and the lower DSM revenues caused a decrease of approximately $44
million and $19 million, respectively. Lower distribution sales volumes,
primarily relating to our industrial customers, reduced revenues by
approximately $25 million. There was an approximate $14 million decrease in
miscellaneous electric revenues primarily relating to replacement capacity
charges (approximately $9 million) and fiber optics (approximately $2 million).
Partially offsetting these decreases were higher commodity sales volumes, which
increased revenues by approximately $47 million and were primarily due to
customers returning to us from TPS as wholesale market prices exceeded the fixed
BGS rates.
Gas Distribution
Gas distribution revenue decreased $46 million or 13% for the quarter ended June
30, 2002 as compared to the quarter ended June 30, 2001 primarily due to
decreased commodity rates (approximately $55 million) offset by increased gas
base rates (approximately $10 million). These rates were adjusted based on our
gas rate case settlement, which became effective January 9, 2002.
Gas distribution revenue decreased $313 million or 22% for the six months ended
June 30, 2002 as compared to the six months ended June 30, 2001 primarily due to
the warmer winter in 2002 (approximately $80 million) and decreased commodity
rates (approximately $270 million) offset by increased gas base rates
(approximately $36 million).
Operating Expenses
Electric Energy Costs
Electric Energy costs increased $11 million or 2% for the quarter ended June 30,
2002 as compared to the quarter ended June 30, 2001 primarily due to higher
commodity sales volumes under the BGS contract with Power (approximately $22
million) and an increase in the amortization of the excess electric distribution
depreciation reserve (approximately $6 million) discussed below in Depreciation
and Amortization, partially offset by lower MTC charges from Power. The lower
MTC charges from Power were principally due to the rate reductions discussed
above in Electric Transmission and Distribution Revenues, which reduced our MTC
costs by approximately $18 million. Overall, changes in the MTC do not have any
impact on our earnings.
Electric Energy costs decreased $10 million for the six months ended June 30,
2002 as compared to the six months ended June 30, 2001 primarily due to the
implementation of a 2% electric rate reduction in February of 2001 and another
2% electric rate reduction in August of 2001 and the effects of weather offset
by higher amounts paid to Power relating to the amortization of the excess
electric distribution depreciation reserve and higher commodity sales volumes.
Gas Costs
Gas Costs decreased $54 million or 22% for the quarter ended June 30, 2002 as
compared to the quarter ended June 30, 2001 primarily due to lower commodity
rates (approximately $55 million) which became effective January 9, 2002.
Gas costs decreased $314 million or 30% for the six months ended June 30, 2002
as compared to the six months ended June 30, 2001 primarily due to lower demand
as a result of the warmer weather in 2002 (approximately $40 million) and
decreased commodity rates (approximately $270 million).
Depreciation and Amortization
Depreciation and Amortization increased $9 million or 10% for the quarter ended
June 30, 2002 as compared to the quarter ended June 30, 2001 primarily due to an
increase in depreciable fixed assets and higher depreciation expense recorded in
accordance with our increased gas base rates. Amortization of the regulatory
asset recorded for our stranded costs increased by approximately $3 million.
Miscellaneous amortization, primarily relating to regulatory assets and
liabilities, increased by approximately $3 million. This was offset by a $6
million reduction relating to higher amortization of the excess electric
distribution depreciation reserve which is equal to a component of the amount we
pay to Power (but we do not collect this component of the rate from customers).
Accordingly, this had no impact on our earnings, but reduced our gross margin
and operating cash flows. For additional information, see Note 3. Regulatory
Assets and Liabilities.
Depreciation and Amortization increased $35 million or 21% for the six months
ended June 30, 2002 as compared to the six months ended June 30, 2001 primarily
due to an increase in depreciable fixed assets, higher depreciation expense
recorded in accordance with our increased gas base rates and an increase of $27
million relating to a full period's recognition of amortization of the
regulatory asset recorded for our stranded costs, whose amortization began in
February 2001. In addition, miscellaneous amortization, primarily relating to
regulatory assets and liabilities, increased by approximately $5 million. This
was offset by an $11 million decrease relating to higher amortization of the
excess electric distribution depreciation reserve.
Other Income
Other Income decreased $18 million or 75% for the quarter ended June 30, 2002 as
compared to the quarter ended June 30, 2001 primarily due to a decrease in
interest income of $16 million and a $2 million decrease in gains relating to
the disposal of assets. Interest income decreased by $6 million due to PSEG
paying off an intercompany note on April 16, 2001. Interest income decreased by
approximately $8 million due to lower amounts of funds being invested in money
markets in the second quarter of 2002 as compared to the prior period.
Other Income decreased $83 million or 88% for the six months ended June 30, 2002
as compared to the six months ended June 30, 2001 primarily due to reduced
interest income of $81 million and a $2 million decrease in gains relating to
the disposal of assets. Interest income decreased by $66 million due to interest
income being recorded in the prior year for intercompany notes from PSEG and
Power. Interest income decreased by approximately $13 million due to lower
amounts of funds being invested in money markets in 2002 as compared to the
prior period.
Interest Expense
Interest Expense decreased $10 million and $25 million or 9% and 11% for the
quarter and six months ended June 30, 2002 as compared to the quarter and six
months ended June 30, 2001 respectively primarily due to reduced levels of
short-term and long-term debt.
Preferred Securities Dividend Requirements of Subsidiaries
Preferred Securities Dividend Requirements of Subsidiaries decreased $3 million
or 43% for the quarter ended June 30, 2002 as compared to the quarter ended June
30, 2001 and $11 million or 61% for the six months ended June 30, 2002 as
compared to the six months ended June 30, 2001 primarily due to redemptions in
March 2001 and June 2001.
Income Taxes
Income taxes decreased $19 million or 106% for the quarter ended June 30, 2002
as compared to the quarter ended June 30, 2001 and $54 million or 57% for the
six months ended June 30, 2002 as compared to the six months ended June 30, 2001
almost entirely due to lower pre-tax income in the current year. Lower pre-tax
book income reduced income tax expense by approximately $18 million and $50
million for the quarter and six months ended June 30, 2002, respectively.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity
We have the following credit facilities for various funding purposes and to
provide liquidity for our $400 million commercial paper program. These
agreements are with a group of banks and provide for borrowings with maturities
of up to one year. As of June 30, 2002, we had no commercial paper outstanding.
The following table summarizes our various facilities as of June 30, 2002:
Expiration Total Primary
Date Facility Purpose
- ------------------------ ----------------- ----------------- -------------
(Millions of Dollars)
364-day Credit Facility June 2003 $200 CP Support
3-year Credit Facility June 2005 200 CP Support
Uncommitted Bilateral
Credit Agreement N/A * Funding
* Availability varies based on market conditions.
Under our Mortgage, we may issue new First and Refunding Mortgage Bonds against
previous additions and improvements, provided that our ratio of earnings to
fixed charges calculated in accordance with our Mortgage is at least 2:1, and/or
against retired Mortgage Bonds. At June 30, 2002, our Mortgage coverage ratio
was 3:1. As of June 30, 2002, 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 financing necessary for our capital program, including refunding of
maturing debt and opportunistic refinancing. We have authorization from the BPU
to issue $1 billion of long-term debt through December 31, 2003 for the
refunding of maturing debt and opportunistic refinancing of debt.
On December 27, 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.
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
$150 million and $112 million to PSEG for the six months ended June 30, 2002 and
2001, respectively.
In prior years, 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 deferral is cured. Currently, there has been no deferral or default.
CAPITAL REQUIREMENTS
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 six months ended June 30, 2002 and 2001, we made net plant additions of
$196 million and $172 million, excluding Allowance for Funds Used During
Construction (AFDC), related to improvements in our transmission and
distribution system, gas system and common facilities. Our plant additions for
the six months ended June 30, 2002 were included in our current year's forecast.
Our projected construction expenditures for the next five years are as follows:
($ Millions)
-----------------------------------------------------------------
2002 2003 2004 2005 2006
----------- -------- --------- -------- ---------
$ 485 $ 440 $ 440 $ 450 $ 465
=========== ======== ========= ======== =========
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 to raise necessary capital.
ACCOUNTING ISSUES
Critical Accounting Policies and Other Accounting Matters
Our most critical accounting policies include the application of: Statement of
Financial Accounting Standards (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. Two of
these items 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 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. The amounts we recover from customers through the MTC
are paid to Power, this does not impact our earnings. 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, the MTC was being recovered at a faster rate than intended under the
Final Order and a significant overrecovery was 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 June 30, 2002, this deferred amount was $185
million, of which $16 million relates to the current year, and is aggregated
with the SBC.
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. Through June
30, 2002, $324 million has been amortized and recorded as a reduction of
depreciation expense pursuant to the Final Order, of which $74 million relates
to 2002. The remaining $245 million will be amortized through July 31, 2003.
See Note 3. 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 or 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. 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
5 - 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 and Basis of
Presentation 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", "projected", "forecast" or variations of such words
and similar expressions are intended to identify forward-looking statements. We
undertake no obligation to publicly update or revise any 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.
Consequently, all of the forward-looking statements made in this report are
qualified by these cautionary statements and we cannot assure you that the
results or developments anticipated by us will be realized, or even if realized,
will have the expected consequences to or effects on us or our business
prospects, financial condition or results of operations. You should not place
undue reliance on these forward-looking statements in making any investment
decision. We expressly disclaim any obligation or undertaking to release
publicly any updates or revisions to these forward-looking statements to reflect
events or circumstances that occur or arise or are anticipated to occur or arise
after the date hereof. In making any investment decision regarding our
securities, we are not making, and you should not infer, any representation
about the likely existence of any particular future set of facts or
circumstances. The forward-looking statements contained in this report are
intended to qualify for the safe harbor provisions of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended.
ITEM 3. 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. See Note 5. Financial Instruments and Risk Management for a
discussion of risks associated with commodity contracts and interest rates.
Credit Risk
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.
PART II. OTHER INFORMATION
--------------------------
ITEM 1. LEGAL PROCEEDINGS
Certain information reported under Item 3 of Part I of Public Service Electric
and Gas Company's (PSE&G) 2001 Annual Report on Form 10-K and the quarterly
report on Form 10-Q for the quarter ended March 31, 2002 is updated below.
In addition see the following at the pages hereof indicated:
(1) Form 10-K, Pages 7 and 8. See Pages 7, 11 and 12 regarding our Gas Contract
Transfer, Docket Nos. GR01050328 and GR01050297.
(2) Form 10-K, Pages 10 and 49. See Page 6 regarding our MGP remediation
program.
(3) Form 10-K, Page 49. See Page 6. Investigation and additional investigation
by the EPA regarding the Passaic River site. Docket No. EX93060255.
(4) March 31, 2002 Form 10-Q, Page 18. Con Edison complaint filed against us at
FERC pursuant to Section 206 of the Federal Power Act. Docket No.
EL02-23-000. See page 20.
(5) New Matter: Atlantic City Electric Co., et al. v. Federal Energy Regulatory
Commission. See page 20.
(6) New Matter: The filing of our electric rate case. See page 12.
ITEM 5. OTHER INFORMATION
Affiliate Standards
Form 10-K, page 6. On February 8, 2002 and March 27, 2002, the BPU issued orders
adopting the Competitive Service Audit reports on the state's electric and gas
utilities. The audit report generally concluded that we were in compliance with
the BPU's Affiliate Standards, and the BPU ordered implementation of 24 of the
auditor's recommendations, to which we did not specifically object.
On July 1, 2002, we filed our Affiliate Standards compliance plan in accordance
with the BPU's regulations. Also in July 2002, the BPU commenced its next
regular audit of the state's electric and gas utilities' competitive activities.
The audit is expected to continue through the Spring of 2003.
Uranium Enrichment Decontamination and Decommissioning Fund
Form 10-K, page 11. In accordance with the 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. Along with other nuclear generator owners, PSEG 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. In July 2002, PSEG withdrew from this lawsuit
without prejudice, due to an unfavorable decision against another nuclear
generator owner in the lawsuit.
FERC Notice of Proposed Rule Making (NOPR)
Form 10-K, page 8. On July 31, 2002 the FERC issued a NOPR to create a Standard
Market Design for the wholesale electricity markets in the United States. The
NOPR seeks to improve the consistency of market rules throughout the country,
including issues related to reliability, market power concerns, transmission,
pricing, congestion, governance and other issues. We cannot predict the outcome
of this matter or its impact upon us if adopted, which could significantly
affect transmission and generation in the various markets in which we operate.
Con Edison Complaint
March 31, 2002 Form 10-Q, Page 18. On November 15, 2001, Consolidated Edison,
Inc. (Con Edison) filed a complaint against us at the Federal Energy Regulatory
Commission (FERC or Commission) pursuant to Section 206 of the Federal Power Act
asserting that we had breached agreements covering 1,000 MW of transmission by
curtailing service and failing to maintain sufficient system capacity to satisfy
all of our service obligations. We denied the allegations set forth in the
complaint. While finding that Con Edison's presentation of evidence failed to
demonstrate several of the allegations, on April 26, 2002, FERC found sufficient
reason to set the complaint for hearing. An initial decision issued by an
administrative law judge on April 25, 2002 upheld our claim that the contracts
do not require the provision of "firm" transmission service to Con Edison but
also accepted Con Edison's contentions that we were obligated to provide service
to Con Edison utilizing all the facilities comprising our electrical system
including generation facilities and that we were financially responsible for
above-market generation costs needed to effectuate the desired power flows.
Under FERC procedures, an initial decision is not binding unless and until its
findings have been approved by the Commission. We filed a brief taking exception
to the adverse findings of the April 25, 2002 order and believe that we have
presented meritorious arguments supporting our interpretation of the contractual
obligations. A Commission decision concerning the findings of the April 25, 2002
order was expected on July 31, 2002. Settlement discussions between the
companies with respect to this matter have been on-going and, on July 17, 2002,
representatives of the companies met for settlement discussions mediated by a
FERC administrative law judge. Based on progress made at these discussions, Con
Edison sought to extend the date for the issuance of the FERC decision
addressing the April 25, 2002 initial decision and to extend the date for the
commencement of a hearing with respect to issues in the case not addressed by
the April 25, 2002 initial decision. At present, in the event the dispute is not
settled, the FERC decision is expected on September 11, 2002 and the hearing
before the administrative law judge will commence in October 2002. If Con Edison
is successful in litigation, we could be required to provide future transmission
services with uneconomic generation resources at a substantial cost to us. The
findings in the April 25, 2002 initial decision notwithstanding, we believe we
have complied with the terms of the Agreements and will vigorously defend our
position. The nature and cost of any remedy, which is expected to be prospective
only, cannot be predicted. Further, even in the event settlement is reached with
Con Edison, we could still be required to bear substantial levels of additional
costs. Docket No. EL02-23-000.
FERC Order and PJM Restructuring
New Matter: Atlantic City Electric Co., et al. v. Federal Energy Regulatory
Commission. On July 12, 2002, the United States Court of Appeals, D.C. Circuit,
issued an opinion in favor of us and the other utility petitioners, reversing an
order of the FERC relating to the restructuring of PJM into an Independent
System Operator (ISO). The Court agreed with our position and ruled that: (1)
FERC lacks authority to require the utility owners to give up their statutory
rights under Section 205 of the Federal Power Act. Hence, FERC was wrong to
require a modification to the PJM ISO Agreement eliminating their rights to file
changes to rate design; (2) FERC lacks authority under Section 203 of the
Federal Power Act to require the utility owners to obtain approval of their
withdrawal from the PJM ISO. Hence, FERC had no right under Section 203 to
eliminate the withdrawal rights to which the utilities had agreed; and (3) As to
our situation, FERC could not accomplish a generic existing precedent, it was
first necessary to make a particularized finding with respect to the public
interest, which was not done here. This decision could be subject to an appeal
to the United States Supreme Court by the respondents, including the FERC.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) A listing of exhibits being filed with this document is as follows:
Exhibit Number Document
-------------- --------
10 Basic Generation Service (BGS) Contract
12 Computation of Ratios of Earnings to Fixed
Charges
12(A) Computation of Ratios of Earnings to Fixed
Charges Plus Preferred Securities
99 Certification by E. James Ferland, Chairman
of the Board and Chief Executive Officer of
Public Service Electric and Gas Company
Pursuant to Section 1350 of Chapter 63 of
Title 18 of the United States Code
99.1 Certification by Robert E. Busch, Senior Vice
President - Finance and Chief Financial
Officer of Public Service Electric and Gas
Company Pursuant to Section 1350 of Chapter
63 of Title 18 of the United States Code
(B) Reports on Form 8-K and 8-K/A:
Date of Report Form Items Reported
-------------- ---- --------------
July 17, 2002 8-K Items 5 and 7
July 29, 2002 8-K/A Items 5 and 7
SIGNATURE
Pursuant to the requirements 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
(Registrant)
By: PATRICIA A. RADO
---------------------------------------
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
Date: August 2, 2002