================================================================================

                                  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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<PAGE>

                                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
<PAGE>

                          PART I. FINANCIAL INFORMATION

                          ITEM 1. FINANCIAL STATEMENTS

                     PUBLIC SERVICE ELECTRIC AND GAS COMPANY
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (Millions)
                                   (Unaudited)

<TABLE>
<CAPTION>
                                                                                        For the                     For the
                                                                                   Three Months Ended          Nine Months Ended
                                                                                 ---------------------        ---------------------
                                                                                      September 30,               September 30,
                                                                                   2002          2001          2002          2001
                                                                                  -------       -------       -------       -------
<S>                                                                               <C>           <C>           <C>           <C>
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
                                                                                  =======       =======       =======       =======
</TABLE>

See Notes to Consolidated Financial Statements.


                                       1
<PAGE>

                     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
<PAGE>

                     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
<PAGE>

                     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
<PAGE>

                   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
<PAGE>

              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
<PAGE>

              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
<PAGE>

              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.

<TABLE>
<CAPTION>
                                                                               September 30, 2002              December 31, 2001
                                                                            ------------------------        -----------------------
                                                                            Carrying           Fair         Carrying          Fair
                                                                             Amount           Value          Amount           Value
                                                                            --------          ------        --------         ------
                                                                                                   (Millions)
<S>                                                                           <C>             <C>             <C>             <C>
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
</TABLE>


                                       8
<PAGE>

              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:

<TABLE>
<CAPTION>
                                                                               Three Months Ended               Nine Months Ended
                                                                                  September 30,                    September 30,
                                                                              -----------------------          --------------------
                                                                               2002             2001            2002          2001
                                                                              -----------------------------------------------------
                                                                                                    (Millions)
<S>                                                                           <C>             <C>               <C>           <C>
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%
</TABLE>

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
<PAGE>

              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

<TABLE>
<CAPTION>
                                                                        Three Months Ended               Nine Months Ended
                                                                           September 30,                    September 30,
                                                                       ---------------------            -------------------
                                                                       2002             2001            2002          2001
                                                                       ----------------------------------------------------
                                                                                             (Millions)
<S>                                                                    <C>             <C>              <C>           <C>
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
                                                                       ====            ====             ====          ====
</TABLE>

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
<PAGE>

                   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
<PAGE>

                 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
<PAGE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

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
<PAGE>

($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
<PAGE>

                    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
<PAGE>

                                    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
<PAGE>

                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
<PAGE>

                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


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