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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 September 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 September 30, 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.
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TABLE OF CONTENTS
PAGE
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements ............................................... 1
Item 2. Management's Discussion and Analysis of Financial Condition and .... 12
Results of Operations
Item 3. Qualitative and Quantitative Disclosures About Market Risk ......... 20
Item 4. Controls and Procedures ............................................ 20
PART II. OTHER INFORMATION
Item 1. Legal Proceedings .................................................. 20
Item 5. Other Information .................................................. 20
Item 6. Exhibits and Reports on Form 8-K ................................... 23
Signature .................................................................. 24
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Millions)
(Unaudited)
For the For the
Three Months Ended Nine Months Ended
--------------------- ---------------------
September 30, September 30,
2002 2001 2002 2001
------- ------- ------- -------
OPERATING REVENUES
Electric Transmission and Distribution .................................. $ 1,164 $ 1,123 $ 2,932 $ 2,952
Gas Distribution ........................................................ 241 272 1,362 1,706
------- ------- ------- -------
Total Operating Revenues ............................................ 1,405 1,395 4,294 4,658
------- ------- ------- -------
OPERATING EXPENSES
Electric Energy Costs ................................................... 696 677 1,797 1,788
Gas Costs ............................................................... 141 177 857 1,207
Operation and Maintenance ............................................... 230 245 721 742
Depreciation and Amortization ........................................... 123 114 316 272
Taxes Other than Income Taxes ........................................... 31 23 97 92
------- ------- ------- -------
Total Operating Expenses ............................................ 1,221 1,236 3,788 4,101
------- ------- ------- -------
OPERATING INCOME ........................................................... 184 159 506 557
Other Income ............................................................... 4 11 15 104
Other Deductions ........................................................... -- (1) (1) (3)
Interest Expense ........................................................... (97) (111) (306) (344)
Preferred Securities Dividend Requirements of Subsidiaries ................. (3) (4) (10) (22)
------- ------- ------- -------
INCOME BEFORE INCOME TAXES ................................................. 88 54 204 292
Income Taxes ............................................................... (32) 11 (73) (84)
------- ------- ------- -------
NET INCOME ................................................................. 56 65 131 208
Preferred Securities Dividend Requirements and Premium
On Redemption ........................................................... (1) -- (3) (4)
------- ------- ------- -------
EARNINGS AVAILABLE TO PUBLIC SERVICE
ENTERPRISE GROUP INCORPORATED ........................................... $ 55 $ 65 $ 128 $ 204
======= ======= ======= =======
See Notes to Consolidated Financial Statements.
1
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
CURRENT ASSETS
Cash and Cash Equivalents ...................... $ 58 $ 102
Accounts Receivable:
Customer Accounts Receivable ................. 515 556
Other Accounts Receivable .................... 73 67
Allowance for Doubtful Accounts .............. (31) (38)
Unbilled Revenues .............................. 160 291
Natural Gas .................................... -- 415
Materials and Supplies ......................... 53 50
Prepayments .................................... 122 40
Energy Contracts ............................... -- 32
Restricted Cash ................................ 14 12
Other .......................................... 23 22
-------- --------
Total Current Assets ......................... 987 1,549
-------- --------
PROPERTY, PLANT AND EQUIPMENT
Electric ....................................... 5,674 5,501
Gas ............................................ 3,401 3,284
Other .......................................... 403 385
-------- --------
Total ........................................ 9,478 9,170
Accumulated Depreciation and Amortization ...... (3,547) (3,329)
-------- --------
Net Property, Plant and Equipment ............ 5,931 5,841
-------- --------
NONCURRENT ASSETS
Regulatory Assets .............................. 5,049 5,247
Long-Term Investments .......................... 121 112
Other Special Funds ............................ 239 130
Other .......................................... 78 84
-------- --------
Total Noncurrent Assets ...................... 5,487 5,573
-------- --------
TOTAL ASSETS ...................................... $ 12,405 $ 12,963
======== ========
See Notes to Consolidated Financial Statements.
2
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions)
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year .............. $ 428 $ 668
Commercial Paper and Loans ...................... 131 --
Accounts Payable ................................ 495 642
Energy Contracts ................................ -- 169
Accrued Taxes ................................... 4 30
Other ........................................... 284 277
-------- --------
Total Current Liabilities ..................... 1,342 1,786
-------- --------
NONCURRENT LIABILITIES
Deferred Income Taxes and Investment Tax
Credit (ITC) .................................. 2,547 2,551
Regulatory Liabilities .......................... 363 373
Other Postemployment Benefit (OPEB) Costs ....... 480 466
Other ........................................... 206 205
-------- --------
Total Noncurrent Liabilities .................. 3,596 3,595
-------- --------
COMMITMENTS AND CONTINGENT LIABILITIES (see Note 4)
CAPITALIZATION
LONG-TERM DEBT
Long-Term Debt ................................ 2,626 2,626
Securitization Debt ........................... 2,259 2,351
-------- --------
Total Long-Term Debt ........................ 4,885 4,977
PREFERRED SECURITIES
Preferred Stock Without Mandatory Redemption .. 80 80
Subsidiaries' Preferred Securities:
Guaranteed Preferred Beneficial Interest in
Subordinated Debentures ..................... 155 155
-------- --------
Total Preferred Securities .................. 235 235
-------- --------
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 ............................. 471 493
Accumulated Other Comprehensive Loss .......... (2) (1)
-------- --------
Total Common Stockholder's Equity ........... 2,347 2,370
-------- --------
Total Capitalization ...................... 7,467 7,582
-------- --------
TOTAL LIABILITIES AND CAPITALIZATION ............... $ 12,405 $ 12,963
======== ========
See Notes to Consolidated Financial Statements.
3
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
For the
Nine Months Ended
September 30,
--------------------
2002 2001
------ ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income .......................................... $ 131 $ 208
Adjustments to reconcile net income to net
cash flows from operating activities:
Depreciation and Amortization ....................... 316 272
Provision for Deferred Income Taxes and ITC ......... (32) (79)
Non-Cash Benefit Plan Costs ........................ 106 113
Non-Cash Interest Expense .......................... 19 6
Over Recovery of Electric Energy Costs and
Market Transition Charge (MTC) .................... 64 47
Under Recovery of Gas Costs ......................... (66) (145)
Net Changes in Certain Current Assets and
Liabilities:
Accounts Receivable and Unbilled Revenues ......... 159 259
Natural Gas ....................................... 415 (78)
Materials and Supplies .......................... (3) (10)
Prepayments ....................................... (82) (134)
Restricted Cash ................................... (2) (6)
Accrued Interest .................................. (19) --
Accrued Taxes ..................................... (26) --
Accounts Payable .................................. (147) (219)
Other Current Assets and Liabilities .............. (21) (12)
Benefit Plan Funding and Payments .................. (187) (109)
Other ............................................... 9 8
----- -------
Net Cash Provided By Operating Activities ......... 634 121
----- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment .......... (322) (268)
----- -------
Net Cash Used in Investing Activities ............. (322) (268)
----- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt ....................... 131 (1,543)
Issuance of Long-Term Debt .......................... 300 2,525
Deferred Issuance Costs ............................. (2) (201)
Redemption/Purchase of Long-Term Debt ............... (632) (326)
Collection of Note Receivable - Affiliated Company .. -- 2,786
Redemption of Preferred Securities .................. -- (448)
Return of Capital ................................... -- (2,265)
Dividends Paid on Common Stock ...................... (150) (112)
Dividends Paid on Preferred Stock ................... (3) (4)
----- -------
Net Cash (Used)/Provided By in Financing
Activities ...................................... (356) 412
----- -------
Net Change in Cash and Cash Equivalents ................ (44) 265
Cash and Cash Equivalents at Beginning of Period ....... 102 39
----- -------
Cash and Cash Equivalents at End of Period ............. $ 58 $ 304
===== =======
Income Taxes Paid ...................................... $ 124 $ 253
Interest Paid .......................................... $ 338 $ 330
See Notes to Consolidated Financial Statements.
4
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 and 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. Following the transfer
of our generation-related assets to Power in August 2000 and our gas supply
portfolio in May 2002, we continue to own and operate our transmission and
distribution business. PSEG owns all of our common stock.
We also have a wholly-owned subsidiary, PSE&G Transition Funding LLC that was
organized for the sole purpose of purchasing and owning bondable transition
property (BTP) of PSE&G and issuing securitization bonds.
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 Quarterly Reports
on Form 10-Q for the three months ended March 31, 2002 and June 30, 2002 and
should be read in conjunction with those reports.
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. Recent Accounting Pronouncements
Statement of Financial Accounting Standard (SFAS) No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142)
On January 1, 2002, we adopted 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 indications of impairment arise. At the date of adoption, we
did 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.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
(SFAS 144)
On January 1, 2002, we adopted SFAS 144. Upon adoption, 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. Also under SFAS 144, discontinued operations
are no longer measured at net realizable value and no longer include amounts for
operating losses that have not yet occurred.
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143)
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143.
Under SFAS 143, the fair value of a liability for an asset retirement obligation
(ARO) is required to be recorded in the period in which it is incurred with an
offsetting amount recorded as 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 any
potential impact on our financial position, results of operations and cash flow.
The 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.
In August 2002, we filed a petition requesting clarification from the New Jersey
Board of Public Utilities (BPU) regarding the future cost responsibility for
nuclear decommissioning and whether, as a matter of law and policy; (a) our
customers will continue to pay for such costs through the Societal Benefits
Clause (SBC) or (b) such customer responsibility will terminate at the end of
the four-year transition period on July 31, 2003. We cannot predict the outcome
of this matter.
SFAS No. 145, "Rescission of FASB Statements Nos. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" (SFAS 145)
During the third quarter of 2002, we adopted SFAS 145. This Statement rescinds
SFAS No. 4, "Reporting Gains and Losses from Extinguishments of Debt," (SFAS 4)
and an amendment of that Statement, SFAS No. 64, "Extinguishments of Debt Made
to Satisfy Sinking Fund Requirements" (SFAS 64). SFAS 4 required that gains and
losses from extinguishments of debt that were included in the determination of
net income be aggregated, and if material, classified as an extraordinary item.
Since the issuance of SFAS 4, the use of debt extinguishments has become part of
the risk management strategy of many companies, representing a type of debt
extinguishment that does not meet the criteria for classification as an
extraordinary item. Based on this trend, the FASB issued this rescission of SFAS
4 and SFAS 64. Accordingly, under SFAS 145, we will record any gains and losses
from extinguishments of debt in Other Income or Other Deductions. We adopted
SFAS 145 retroactive to January 1, 2002, with no impact to our financial
position, results of operations, or net cash flows.
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities"
(SFAS 146)
In June 2002, the FASB issued SFAS 146, which addresses the financial accounting
and reporting for costs associated with exit or disposal activities. SFAS 146
states that a liability for a cost associated with an exit or disposal activity
shall be recognized and measured initially at its fair value in the period when
the liability is incurred. A liability is established only when present
obligations to others are determined. SFAS 146 does not apply to costs
associated with the retirement of long-lived assets covered in SFAS 143. It
applies to costs associated with an exit activity that does not involve an
entity newly acquired in a business combination or with a disposal activity
covered by SFAS 144. We will apply SFAS 146 for exit or disposal activities
initiated after December 31, 2002, in accordance with the effective date of the
standard.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
Note 3. Regulatory Assets and Liabilities
At September 30, 2002 and December 31, 2001, respectively, we had deferred the
following regulatory assets and liabilities on the Consolidated Balance Sheets:
---------------------------
September 30, December 31,
2002 2001
------------- ------------
(Millions)
Regulatory Assets
- -----------------
Stranded Costs To Be Recovered ....................... $3,936 $4,105
SFAS 109 Income Taxes ................................ 318 302
Other Postretirement Benefit Plan (OPEB) Costs ....... 198 212
Societal Benefits Charges (SBC) ...................... -- 4
Manufactured Gas Plant Remediation Costs ............. 87 87
Unamortized Loss on Reacquired Debt and Debt Expense . 88 92
Under Recovered Gas Costs ............................ 182 120
Unrealized Losses on Gas Contracts ................... -- 137
Unrealized Losses on Interest Rate Swap .............. 65 18
Repair Allowance Taxes ............................... 93 84
Decontamination and Decommissioning Costs ............ 25 25
Plant and Regulatory Study Costs ..................... 27 31
Regulatory Restructuring Costs ....................... 27 27
Other ................................................ 3 3
------ ------
Total Regulatory Assets ........................ $5,049 $5,247
====== ======
Regulatory Liabilities
- ----------------------
Excess Depreciation Reserve .......................... $ 208 $ 319
Over Recovered Electric Energy Costs (BGS and NTC) ... 96 48
SBC .................................................. 47 --
Other ................................................ 12 6
------ ------
Total Regulatory Liabilities ................... $ 363 $ 373
====== ======
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 the
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 own or owned and/or operate 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.
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
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 September 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
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 entities, 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 within the Passaic River "facility". 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 under a contract, 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
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 September 30, 2002 and December 31, 2001, respectively.
September 30, 2002 December 31, 2001
------------------------ -----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ------ -------- ------
(Millions)
Long-Term Debt:
PSE&G ......................................................... $2,926 $3,242 $3,173 $3,290
Transition Funding ............................................ 2,387 2,579 2,472 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 97 95 96
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
Commodity-Related Instruments - 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. 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 $(65) million as of
September 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 Sheets. 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:
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- --------------------
2002 2001 2002 2001
-----------------------------------------------------
(Millions)
Pre-Tax Income ..................................................... $88 $54 $204 $292
Tax Computed at the Federal Statutory Rate at 35% .................. 30 19 71 102
Increases (decreases) from Federal
statutory rate attributable to:
State Income Taxes after Federal Benefit ....................... 7 4 17 22
Plant Related Items ............................................ (3) (31) (10) (41)
Other .......................................................... (2) (3) (5) 1
-----------------------------------------------------
Total Income Tax (Benefit) Expense ................................. 32 $(11) $ 73 $ 84
-----------------------------------------------------
Effective Income Tax Rate .................................... 36.3% (20.4)% 35.8% 28.8%
The increase in the effective tax rate for the three and nine months ended
September 30, 2002, as compared to the same periods for 2001, is due primarily
to the conclusion of the 1994-1996 Internal Revenue Service (IRS) audit and upon
filing our actual tax return for the year 2000.
Note 7. Financial Information by Business Segments
Following the transfer of our generation-related assets to PSEG Power LLC
(Power) in August 2000, we continue to own and operate our transmission and
distribution (T&D) business as our only reportable segment.
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-Continued
(UNAUDITED)
Note 8. Comprehensive Income
For the three months ended September 30, 2002 and 2001, our comprehensive income
was $56 million and $65 million, respectively. For the nine months ended
September 30, 2002 and 2001, our other comprehensive income (loss) (OCI) was
$(1) million and $2 million, respectively, relating to our minimum pension
liability. For the nine months ended September 30, 2002 and 2001, our
comprehensive income was $130 million and $210 million, respectively.
Note 9. Other Income
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- -------------------
2002 2001 2002 2001
----------------------------------------------------
(Millions)
Other Income
Interest Income ........................................ $ 4 $ 9 $ 13 $ 99
Gain on Disposition of Property ........................ -- 1 1 4
Other .................................................. -- 1 1 1
---- ---- ---- ----
Total Other Income ......................................... $ 4 $ 11 $ 15 $104
==== ==== ==== ====
Note 10. Related-Party Transactions
PSEG AND POWER
In August 2000, we transferred our electric generation assets and liabilities to
Power in exchange for a $2.8 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 $1.1 billion to PSEG at 14.23% per
annum and recorded interest income of approximately $33 million relating to the
loan for the nine month period ended September 30, 2001. PSEG repaid the loan on
April 16, 2001. We also returned $2.3 billion of capital to PSEG on January 31,
2001 utilizing proceeds from the $2.5 billion securitization transaction and the
generation asset transfer, as required by the Final Order from the BPU, as part
of our recapitalization.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Concluded
Effective with the transfer of the electric generation business, Power charges
us for the Market Transition Charge (MTC) and charged us for the energy and
capacity provided to meet our Basic Generation Service (BGS) requirements
through July 31, 2002. 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 September 30, 2002 and 2001, respectively, we
were charged by Power approximately $216 million and $568 million for the MTC
and BGS. For the nine months ended September 30, 2002 and 2001, respectively, we
were charged by Power approximately $1.2 billion and $1.5 billion for the MTC
and BGS. As of December 31, 2001, our payable to Power relating to these costs
was approximately $159 million. With commencement of the new BGS contract period
on August 1, 2002, Power charges us only for the MTC. As of September 30, 2002
our payable to Power relating to these costs was approximately $1 million.
For the quarters ended September 30, 2002 and 2001, respectively, we sold energy
and capacity to Power at market prices totaling approximately $48 million and
$55 million, which we purchased under various non-utility generation (NUG)
contracts at costs above market prices. For the nine months ended September 30,
2002 and 2001, these sales totaled $110 million and $135 million, respectively.
As of September 30, 2002 and December 31, 2001, our receivable related to these
purchases was approximately $13 million and $7 million, respectively. With
commencement of the new BGS contract period on August 1, 2002, we can sell the
energy purchased under the NUG contracts in a PJM administered market.
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 and third parties, which are priced at the locational
marginal price (LMP) set by Pennsylvania-New Jersey-Maryland Power Pool (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
requirements 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 Basic Gas Supply Service
(BGSS) requirements. The contract term ends March 31, 2004, after which we have
a three-year renewal option. As part of the agreement, we are providing Power
the use of our peak shaving facilities at cost. The net billings under this
contract for the three and nine months ended September 30, 2002 were
approximately $111 million and $208 million, respectively. As of September 30,
2002, our net payable to Power relating to these costs was approximately $38
million.
PSEG SERVICES CORPORATION
PSEG Services Corporation provides administrative services to us and bills us
for them on a monthly basis. Our costs related to such services amounted to
approximately $46 million and $55 million for the quarters ended September 30,
2002 and 2001, respectively. These costs totaled $149 million and $171 million
for the nine months ended September 30, 2002 and 2001, respectively. As of
September 30, 2002 and December 31, 2001, our payable related to these costs was
approximately $15 million and $25 million, respectively.
11
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 and 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 (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 Quarterly Reports on Form 10-Q for the
quarters ended March 31, 2002 and June 30, 2002 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
For the quarter ended September 30, 2002, net income decreased $9 million or 14%
as compared to the quarter ended September 30, 2001 primarily due to higher
income tax expense. Offsetting the tax expense increase was an increase in our
electric and gas margins (approximately 5%), primarily due to increased electric
volumes, and lower (approximately 6%) operations and maintenance expense. The
tax expense increase was due to adjustments recorded in 2001 as a result of the
completion of the 1994-1996 Internal Revenue Service (IRS) audit and the actual
filing of the 2000 tax return. For further discussion, see Results of
Operations.
For the nine months ended September 30, 2002, net income decreased $77 million
or 37% as compared to the nine months ended September 30, 2001 primarily due to
a decrease in our operating margin on our electric and gas business and a
decrease in other income. While our electric margin decreased (approximately
2%), primarily due to lower Demand Side Management (DSM) and fiber optic sales,
our gas margins increased (approximately 1%) due to an increase in gas base
rates offset by lower sales volumes due to weather. The decrease in other income
was due to intercompany notes with PSEG and Power, which were repaid in early
2001. For further discussion, see Results of Operations.
Our cash position decreased $44 million from December 31, 2001 to September 30,
2002 primarily due to $322 million and $356 million of cash outflows for
investing and financing activities, respectively, offset by $634 million of
operating cash inflows. The operating cash inflows were primarily comprised of
the gas contract transfer to PSEG Power LLC (Power), the restructuring of our
non-utility generation (NUG) contract with El Paso Merchant Energy, and cash
earnings during the period offset by benefit plan payments and 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 Transition Funding LLC (Transition Funding)'s transition
bonds, the maturity of long-term debt, and cash dividends paid on common and
preferred stock offset by the issuance of long and short-term debt.
Our future cash activities will be impacted by various factors, including the
recent Basic Generation Service (BGS) auction, which went into effect August 1,
2002. We have contracted for our energy needs for our expected peak load of
9,600 MW for the period August 1, 2002 through July 31, 2003. The difference
between the current auction contract prices and the amount we are recovering
from customers will result in a underrecovery of BGS costs of approximately $240
million annually, which will be deferred and collected from our customers with
interest as provided in the New Jersey Board of Public Utilities (BPU) Order
approving the auction process. In addition, recent downturns in the stock
markets could affect the value of our pension plans that may result in a charge
to our
12
stockholders' equity at year-end. If required, this would result in an increase
to our debt to capitalization ratio. See Accounting Matters for further
information.
Under the Basic Gas Supply Service (BGSS) requirements, our gas costs in excess
of (or below) the amount included in current commodity rates, are probable of
being recovered from (returned to) customers through future commodity rates.
Under SFAS 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS
71), we defer (record) costs in excess of (or below) the amount included in
current commodity rates. Therefore any increase or decrease in our gas commodity
revenue is offset by a corresponding increase or decrease in gas costs on the
income statement.
Underrecovered gas costs do not accrue interest, unless specifically approved by
the BPU, while overrecovered gas costs do accrue interest. The BGSS rate is
normally adjusted on an annual basis. In September 2002, we filed to increase
our Residential Basic Gas Supply Service (BGSS) Commodity Charge to recover
approximately $89 million in additional revenues, which includes $83 million for
underrecovered costs accumulated since October 31, 2001.
On January 9, 2002 the BPU approved the recovery of our underrecovered BGSS
(formerly LGAC) balance at October 31, 2001 of $130 million plus interest
through a Gas Cost Underrecovery Adjustment (GCUA). This balance is being
recovered, with interest over a three-year period ending September 2004. The
underrecovered balance at September 30, 2002 is $115 million.
Our success will be dependent, in part, on our ability to obtain a reasonable
outcome, which cannot be assured, to our recently filed electric rate case as
well as our ability to continue to recover the regulatory assets we have
deferred and the investments we plan to make in our electric and gas
transmission and distribution systems. Mitigating this rate increase to
customers are overrecoveries of the SBC and NTC and the potential securitization
of the expected BGS underrecovery. As part of the deregulation process, as of
September 30, 2002, we have implemented BPU-mandated rate reductions totaling
13.9% since August 1, 1999, including a 4.9% rate reduction effective August 1,
2002, which will be in effect until July 31, 2003. This rate reduction reduces
the MTC revenues and is offset by a corresponding decrease in energy costs as it
reduces the rate that Power charges us and therefore has no impact on our
operating margins.
RESULTS OF OPERATIONS
Operating Revenues
Electric Transmission and Distribution
Electric Transmission and Distribution revenues increased $41 million or 4% for
the quarter ended September 30, 2002 as compared to the quarter ended September
30, 2001, primarily due to higher BGS revenues (approximately $43 million) due
to increased residential volumes from favorable weather conditions. Partially
offsetting this increase was the implementation of a 4.9% electric retail rate
reduction in August of 2002 and a 2% rate reduction in August 2001
(approximately $42 million). These rate reductions are recorded as Market
Transition Charge (MTC) revenues. Changes in the BGS/MTC revenues are offset by
a corresponding amount in energy costs, discussed below, and have no impact on
net income. Other revenue changes included higher distribution sales volumes
primarily due to favorable weather conditions (approximately $39 million), and
higher transmission revenues (approximately $3 million) due to higher payments
from PJM for the use of our transmission system. These increases were offset by
a decrease in fiber optic revenue (approximately $2 million), due to unfavorable
market conditions.
Electric Transmission and Distribution revenues decreased $20 million or 1% for
the nine months ended September 30, 2002 as compared to the nine months ended
September 30, 2001 primarily due to the implementation of a 4.9% electric retail
rate reduction in August 2002 and two additional retail rate reductions in
February and August 2001 totaling 4% (approximately $85 million) and reduced NUG
sales due to lower market rates (approximately $13 million). Partially
offsetting these decreases were higher BGS or commodity sales volumes
(approximately $90 million), primarily due to favorable weather conditions. Rate
reductions are recorded as MTC revenues. Changes in
13
the BGS, MTC and NUG revenues are offset by a corresponding amount in energy
costs, discussed below, and have no impact on net income. Other revenue changes
included higher distribution sales volumes primarily due to favorable weather
conditions (approximately $4 million), higher transmission revenues
(approximately $18 million), due to higher payments from PJM for the use of our
transmission system, lower replacement capacity charges (approximately $7
million), lower DSM sales due to revenue adjustments in 2001 (approximately $19
million) and a decrease in fiber optic revenue (approximately $5 million), due
to unfavorable market conditions.
Gas Distribution
Gas distribution revenues decreased $31 million or 11% for the quarter ended
September 30, 2002 as compared to the quarter ended September 30, 2001 primarily
due to decreased commodity revenues from lower commodity rates (approximately
$16 million), lower sales to interruptible customers due to lower sales volumes
at lower rates (approximately $12 million), lower sales volumes primarily due to
weather (approximately $8 million) and lower off-system sales revenues
(approximately $6 million). The lower sales volumes to interruptible customers
resulted from less usage by cogenerators for operations at the customers'
facilities. These decreases were offset by increased gas base rates
(approximately $7 million), which became effective January 9, 2002 and increased
other operating revenues (approximately $3 million). Changes in commodity
revenues and revenues from sales to interruptible customers are offset by
corresponding changes in gas costs, discussed below.
Gas distribution revenues decreased $344 million or 20% for the nine months
ended September 30, 2002 as compared to the nine months ended September 30, 2001
primarily due to decreased commodity rates (approximately $176 million), lower
sales to interruptible customers (approximately $111 million), lower sales
volumes primarily from the warmer winter in 2002 (approximately $90 million),
lower off-system sales revenues (approximately $14 million) partially offset by
increased gas base rates (approximately $43 million) and higher other operating
revenues (approximately $7 million). Changes in commodity revenues and revenues
from sales to interruptible customers are offset by corresponding changes in gas
costs, discussed below.
Operating Expenses
Electric Energy Costs
Electric Energy costs increased $19 million or 3% for the quarter ended
September 30, 2002 as compared to the quarter ended September 30, 2001 primarily
due to higher commodity sales volumes under the BGS contract (approximately $43
million), increases in the amortization of the excess electric distribution
depreciation reserve (approximately $6 million) discussed below in Depreciation
and Amortization, increases in MTC charges from Power, other than rate
reductions, (approximately $6 million) and increases in Non-Utility Generation
Transition Charge (NTC) costs due to higher sales volumes (approximately $3
million). Partially offsetting the increases is the impact of the rate
reductions (approximately $42 million) discussed above in Electric Transmission
and Distribution Revenues.
Electric Energy costs increased $9 million or 1% for the nine months ended
September 30, 2002 as compared to the nine months ended September 30, 2001
primarily due to higher commodity sales volumes under the BGS contract
(approximately $90 million) and higher amounts paid to Power relating to the
amortization of the excess electric distribution depreciation reserve
(approximately $22 million). Partially offsetting the increases is the impact of
the rate reductions (approximately $85 million) discussed above in Electric
Transmission and Distribution Revenues and lower NUG energy sales (approximately
$13 million) due to lower market rates and lower MTC charges from Power, other
than rate reductions, (approximately $4 million).
14
Gas Costs
Under the BGSS, our gas costs in excess of (or below) the amount included in
current commodity rates, are probable of being recovered from (returned to)
customers through future commodity rates. Under SFAS 71, we defer (record) costs
in excess of (or below) the amount included in current commodity rates.
Therefore any increase or decrease in our gas commodity revenue is offset by a
corresponding increase or decrease in gas costs on the income statement.
Gas Costs decreased $36 million or 20% for the quarter ended September 30, 2002
as compared to the quarter ended September 30, 2001 primarily due to lower
commodity rates (approximately $16 million), which became effective January 9,
2002, lower revenues from interruptible customers (approximately $12 million)
due to lower volumes at lower rates and lower off-system sales revenues
(approximately $5 million) due to lower volumes.
Gas costs decreased $350 million or 29% for the nine months ended September 30,
2002 as compared to the nine months ended September 30, 2001 primarily due to
lower commodity costs (approximately $176 million), lower revenues from
interruptible customers (approximately $111 million) due to lower volumes at
lower rates and lower sales volumes as a result of the warmer weather in 2002
(approximately $52 million) and lower off-system sales revenues (approximately
$9 million).
Operation and Maintenance
Operation and Maintenance decreased $15 million or 6% for the quarter ended
September 30, 2002 as compared to the quarter ended September 30, 2001 primarily
due to a management initiative to lower operation and maintenance. As a result,
maintenance expenses were lower (approximately $5 million), membership fees
decreased (approximately $1 million), and equipment rental expenses were lower
(approximately $2 million). Other items contributing to the reduction were lower
medical insurance expenses (approximately $2 million) due to a change in the
medical claim experience, lower Other Postretirement Benefit Plan (OPEB) charges
(approximately $2 million) due to a change in the plan, and a decrease in the
limited term supplemental death benefit premiums (approximately $1 million).
Operation and Maintenance decreased $21 million or 3% for the nine months ended
September 30, 2002 as compared to the nine months ended September 30, 2001
primarily due to a management initiative to lower operation and maintenance. As
a result, maintenance expenses were lower (approximately $11 million),
membership fees decreased (approximately $2 million), and equipment rental
expenses were lower (approximately $6 million). Other items contributing to the
reduction were lower medical insurance expenses (approximately $2 million) due
to a change in the medical claim experience, and lower OPEB charges
(approximately $4 million) due to a change in the plan.
Depreciation and Amortization
Depreciation and Amortization increased $9 million or 8% for the quarter ended
September 30, 2002 as compared to the quarter ended September 30, 2001 primarily
due to an increase in depreciable fixed assets (approximately $4 million),
higher depreciation expense recorded in accordance with our increased gas base
rates (approximately $2 million) and amortization related to securitization
(approximately $9 million). The increases were partially offset by higher
amortization of the excess electric distribution depreciation reserve
(approximately $6 million), 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 $44 million or 16% for the nine months
ended September 30, 2002 as compared to the nine months ended September 30, 2001
primarily due to a full period's recognition of amortization of the regulatory
asset recorded for our stranded costs (approximately $33 million), whose
amortization began in February 2001. Also contributing was an increase in
depreciable fixed assets (approximately $15 million) and higher depreciation
expense recorded in accordance with our increased gas base rates (approximately
$5 million).
15
In addition, miscellaneous amortization increased, primarily relating to
regulatory assets and liabilities (approximately $8 million). These were
partially offset by a decrease relating to higher amortization of the excess
electric distribution depreciation reserve (approximately $17 million). For
additional information, see Note 3. Regulatory Assets and Liabilities.
Other Income
Other Income decreased $7 million or 64% for the quarter ended September 30,
2002 as compared to the quarter ended September 30, 2001 primarily due to a
decrease in interest income (approximately $3 million) due to lower amounts of
funds being invested in money markets in 2002 as compared to the prior period.
Also, contributing was the decrease in gains relating to the disposal of assets
(approximately $3 million).
Other Income decreased $89 million or 86% for the nine months ended September
30, 2002 as compared to the nine months ended September 30, 2001 primarily due
to decreases in interest income from related party notes to PSEG and Power,
which were repaid through April 16, 2001 (approximately $67 million), lower
amounts of funds being invested in money markets in 2002 as compared to the
prior period (approximately $15 million) and a decrease in gains relating to the
disposal of assets (approximately $3 million).
Interest Expense
Interest Expense decreased $14 million or 13% for the quarter ended September
30, 2002 as compared to the quarter ended September 30, 2001, primarily due to
carrying charges on deferred repair allowances (approximately $5 million) and
the maturity of certain debt (approximately $5 million). Lower interest expense
as a result of the repayment of a portion of Transition Funding's securitization
bonds (approximately $2 million) and the redemption of Pollution Control Bonds
(approximately $1 million) also contributed to the decrease.
Interest Expense decreased $38 million or 11% for the nine months ended
September 30, 2002 as compared to the nine months ended September 30, 2001, due
to the redemption of short-term debt in the third quarter of 2001 and lower
interest rates in 2002 (approximately $24 million), the redemption of a floating
rate note in 2001 (approximately $6 million), the maturity of long-term debt
(approximately $9 million), the repurchase of Pollution Control Bonds
(approximately $2 million), the carrying costs on the deferred repair allowance
(approximately $4 million) and state accrued tax interest adjustments
(approximately $2 million). These decreases were partially offset by higher
securitization bond interest expense (approximately $9 million) related to
Transition Funding's securitization bonds.
Preferred Securities Dividend Requirements of Subsidiaries
Preferred Securities Dividend Requirements of Subsidiaries decreased $1 million
or 25% for the quarter ended September 30, 2002 as compared to the quarter ended
September 30, 2001 and $12 million or 55% for the nine months ended September
30, 2002 as compared to the nine months ended September 30, 2001 primarily due
to redemptions in 2001.
Income Taxes
Income taxes increased $43 million for the quarter ended September 30, 2002 as
compared to the quarter ended September 30, 2001 due partially to higher income
in the current quarter. Prior period tax adjustments recorded in 2001 reflecting
the conclusion of the 1994-96 IRS audit settlement and the actual filing of the
2000 tax return also contributed to the increase.
16
Income taxes decreased $11 million or 13% for the nine months ended September
30, 2002 as compared to the nine months ended September 30, 2001 primarily due
to lower income in the current year, offset by the prior period adjustments
discussed above.
LIQUIDITY AND CAPITAL RESOURCES
Financing Methodology
Our capital requirements are met through liquidity provided by internally
generated cash flow and external financings. External funding to meet our needs
is comprised of corporate finance transactions. The debt incurred is our direct
obligation. As discussed below, external financing may consist of public and
private capital market debt, bank revolving credit and term loan facilities
and/or commercial paper.
The availability and cost of external capital could be affected by our
performance as well as by the performance of our affiliates. 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.
Over the next several years, we will be required to refinance maturing debt and
expect to incur additional debt and fund investment activity. Also, from time to
time, we may repurchase debt using funds from operations, commercial paper, debt
issuances and other sources of funding. 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
adversely affect our financial condition, results of operations and net cash
flows.
Debt Covenants, Cross Default Provisions, Material Adverse Clause Changes, and
Ratings Triggers
The PSEG credit agreements contain cross-default provisions under which a
default by it or its major subsidiaries (PSE&G, Power, Energy Holdings) in an
aggregate amount of $50 million would result in a default and the potential
acceleration of payment under the agreements.
Our First and Refunding Mortgage (Mortgage) and credit agreements have no
cross-defaults. Our Medium Term Note Indenture has a cross-default to the PSE&G
Mortgage. The credit agreements have cross-defaults under which a default by us
in the aggregate of $50 million would result in a default and the potential
acceleration of payment under the credit agreements.
A failure to make principal and or interest payments, when due, would be a
default under our credit agreements and indentures. Any inability to satisfy
required covenants and/or borrowing conditions would have a similar impact. If a
default were to occur, the respective lenders and debt holders, after giving
effect to any applicable grace and/or cure periods, could determine that debt
payment obligations may be accelerated. In the event of any likely default or
failure to satisfy covenants or conditions, we, or the relevant subsidiary,
would seek to renegotiate terms of the agreements with the lenders. No
assurances can be given as to whether these efforts would be successful. A
declaration of cross-default could severely limit our liquidity and restrict the
ability to meet respective debt and, in extreme cases, operational cash
requirements which could have a material adverse effect on our financial
condition, results of operations and net cash flows, and those of our
subsidiaries.
The credit agreements generally contain provisions under which the lenders could
refuse to advance loans in the event of a material adverse change in the
borrower's business or financial condition. In that event, loan funds may not be
advanced.
17
As explained in detail below, some of these credit agreements also contain
maximum debt to equity ratios, minimum cash flow tests and other restrictive
covenants and conditions to borrowing. Compliance with applicable financial
covenants will depend upon our future financial position and the level of
earnings and cash flow, as to which no assurances can be given.
The debt indentures and credit agreements do not contain any material "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.
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 September 30, 2002, we had $94 million in commercial
paper and $37 million in uncommitted loans outstanding.
The following table summarizes our various facilities as of September 30, 2002:
Expiration Total Primary
Date Facility Purpose
- ----------------------- ---------- -------- ----------
(Millions)
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.
Financial covenants contained in our credit facilities include a ratio of
Long-Term Debt (excluding Long-Term Debt Maturing within 1 Year) to Total
Capitalization covenant. This covenant requires that at the end of any quarterly
financial period, such ratio will not be more than 0.65 to 1. As of September
30, 2002, our ratio of Long-Term Debt to Total Capitalization was 0.508 to 1.
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 September 30, 2002, our Mortgage coverage
ratio was 3:1. As of September 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 are required 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 up to an aggregate of $1 billion of
long-term debt through December 31, 2003 for the refunding of maturing debt and
opportunistic refinancing of debt. We currently have authorization from the BPU
to issue up to $2 billion in short-term debt through December 31, 2002. In
October 2002, we filed a petition with the BPU requesting authority to issue up
to $750 million of short-term debt through January 4, 2005. In addition, we
expect to securitize approximately $250 million of deferred BGS costs, the
proceeds of which will be used to reduce short-term debt.
In August 2002, $257 million of 6.125% Series RR Mortgage Bonds matured.
In September 2002 we issued $300 million of 5.125% Medium-Term Notes due 2012,
the proceeds of which were used to repay $290 million of 7.19% Medium-Term Notes
that matured.
For the nine months ended September 30, 2002, we have repaid $85 million of
Transition Funding's securitization bonds.
18
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 nine months ended September 30,
2002 and 2001, respectively.
ACCOUNTING MATTERS
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. Recent Accounting Pronouncements, respectively.
SFAS No. 87 - "Employers' Accounting for Pensions" (SFAS 87)
SFAS 87 requires a pension plan sponsor to recognize an additional minimum
pension liability to the extent that its accumulated benefit obligation under
any of its pension plans exceeds the fair market value of its plan assets as of
its annual measurement date. This additional minimum pension liability
represents the amount by which the unfunded accumulated benefit obligation
exceeds the fair market value of the plan's assets, and is partially offset by
an intangible asset no larger than the unrecognized net transition obligation
and prior service cost, with no impact to earnings. At this time, we are
monitoring the fair market value of our investments and our accumulated benefit
obligation and are evaluating options available to us with respect to this
issue. Since our measurement date is December 31, 2002 we are unable to predict
what the impact could be, however the impact could be material to our financial
position and, more specifically, could result in a decrease in equity.
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.
19
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
There were no material changes from the disclosures in our Form 10-K filed with
the Securities and Exchange Commission for the year ended December 31, 2001.
ITEM 4. CONTROLS AND PROCEDURES
We have established and maintain disclosure controls and procedures which are
designed to provide reasonable assurance that material information relating to
us, including our consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this quarterly
report is being prepared. We have established a Disclosure Committee which is
made up of several key management employees and reports directly to the Chief
Financial Officer and Chief Executive Officer, to monitor and evaluate these
disclosure controls and procedures. The Chief Financial Officer and Chief
Executive Officer have evaluated the effectiveness of our disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"). Based on this evaluation, we have
concluded that our disclosure controls and procedures were effective in
providing reasonable assurance during the period covered in this quarterly
report. There were no significant changes in internal controls or in other
factors that could significantly affect internal controls subsequent to the date
of our most recent evaluation.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Certain information reported under Item 3 of Part I of our 2001 Annual Report on
Form 10-K and the Quarterly Reports on Form 10-Q for the quarters ended March
31, 2002 and June 30, 2002 are updated below.
In addition see the following at the pages hereof indicated:
(1) Form 10-K, Pages 7 and 8. See Pages 13 and 21 regarding our Gas
Contract Transfer, Docket Nos. GR01050328 and GR01050297.
(2) Form 10-K, Pages 10 and 49. See Page 8 regarding our MGP remediation
program.
(3) Form 10-K, Page 49. See Page 8. Investigation and additional
investigation by the EPA regarding the Passaic River site. Docket
No. EX93060255.
(4) June 30, 2002 Form 10-Q, Page 15. See page 21. The filing of our
electric retail rate case.
ITEM 5. OTHER INFORMATION
Con Edison Complaint
March 31, 2002 Form 10-Q/A, Page 44 and June 30, 2002 Form 10-Q, Page 55. On
November 15, 2001, Consolidated Edison, Inc. (Con Edison) filed a complaint
against us at FERC 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 in April 2002, FERC found sufficient reason to set the
complaint for hearing. An initial decision issued by an administrative law judge
in April 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
20
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 administrative law judge initial decision
is not binding unless and until its findings have been approved by FERC. We
filed a brief taking exception to the adverse findings of the April 25, 2002
order. A FERC 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 and subsequent
discussions, Con Edison has twice 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 in mid-November, 2002
and the hearing before the administrative law judge will commence in early
December 2002. 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
June 30, 2002 Form 10-Q, Page 24. 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. The Court agreed with our position and
ruled that 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. The court further noted that 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. Further, in ruling on a specific argument raised by us,
the Court held that FERC had not justified its decision to generically abrogate
wholesale power requirements contracts; FERC was required to make a
particularized finding with respect to the public interest, which was not done
here. This matter is now pending on remand before the FERC.
Gas Contract Transfer
June 30, 2002 Form 10-Q, Pages 7 and 8. On January 9, 2002, through approval of
a stipulated settlement, the BPU authorized the transfer of our interstate
capacity, storage and gas supply contracts to an unregulated affiliate to
provide the gas supply BGSS customers. The Ratepayer Advocate's motion for
reconsideration of this approval has been denied by the BPU.
Electric Retail Rate Case
June 30, 2002 Form 10-Q, Page 15. On May 24, 2002, we filed an electric rate
case with the 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 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 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
21
($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, took 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 would 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.
As directed by the BPU in its July 22, 2002 Order, on August 28, 2002, we filed
supplemental testimony to address the use of securitization proceeds and
proceeds from the sale of generation assets. The issue of electronic meters must
also be addressed in a separate filing in an expedited timeframe. We are also
working to resolve the open Service Company filing and our Street Lighting
Tariff. If not resolved, these issues may be consolidated into the rate case.
The electric base rate case is scheduled to be transferred from the Office of
Administrative Law back to the BPU by May 1, 2003. The Ratepayer Advocate and
other parties filed testimony in this case in October 2002 and the case is on
schedule.
Deferral Proceeding
New Matter. In August 2002, we filed a Petition proposing changes to the SBC and
NTC. The proposed result, if adopted, would result in a reduction of revenues of
about $122 million or approximately a 3.4% reduction in amounts paid by
customers, effective on August 1, 2003. The case has been transferred to the
Office of Administrative Law.
Deferral Audit
New Matter. In September 2002, the BPU retained the services of two audit firms
to conduct a review of the State's electric utilities deferred costs for
compliance with BPU orders. We have estimated our overrecovery balance will be
approximately $30 million by the end of July 2003.
BGSS Filing
New Matter. In September 2002, we filed to increase our Residential BGSS
Commodity Charge by November 1, 2002 to recover approximately $89 million in
additional revenues ($83 million of which is associated with an underrecovered
balance) or a 7.4% rate increase for the typical residential gas heating
customer.
Nuclear Decommissioning
New Matter. In August 2002, we filed a Petition requesting clarification from
the BPU regarding the future cost responsibility for nuclear decommissioning and
whether, as a matter of law and policy, (a) Our customers will continue to pay
for such costs through the SBC or (b) such customer responsibility will
terminate at the end of the four-year transition period on July 31, 2003. We
cannot predict the outcome of this matter.
22
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
-------------- --------
4 Supplemental Indenture to First and Refunding Mortgage
between PSE&G and Wachovia Bank, National Association, as
Trustee.
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:
Date Form Items
---- ---- -----
October 11, 2002 8-K 5 & 7
July 29, 2002 8-K/A 5 & 7
July 18, 2002 8-K 5 & 7
23
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: /s/ Patricia A. Rado
------------------------------------
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
Date: November 1, 2002
24
Certification Pursuant to Rules 13a-14 and 15d-14
of the 1934 Securities Exchange Act
I certify that:
1. I have reviewed this quarterly report on Form 10-Q of Public Service
Electric and Gas Company (the registrant);
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of Public Service Enterprise Group's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: November 1, 2002 /s/ E. James Ferland
---------------- ---------------------------------
E. James Ferland
Chief Executive Officer
25
Certification Pursuant to Rules 13a-14 and 15d-14
of the 1934 Securities Exchange Act
I certify that:
1. I have reviewed this quarterly report on Form 10-Q of Public Service
Electric and Gas Company (the registrant);
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we
have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of Public Service Enterprise Group's board of directors:
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: November 1, 2002 /s/ Robert E. Busch
---------------- --------------------------------
Robert E. Busch
Chief Financial Officer
26