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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549

                                    FORM 10-Q
              (Mark One)
                [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR
                      15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
                      For the quarterly period ended June 30, 2002

                                       OR

                 [ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR
                      15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
                      For the transition period from ____ to  ____


 Commission           Registrant, State of Incorporation,      I.R.S. Employer
 File Number             Address, and Telephone Number        Identification No.
--------------- -------------------------------------------  -------------------
  001-00973        PUBLIC SERVICE ELECTRIC AND GAS COMPANY        22-1212800
                          (A New Jersey Corporation)
                                80 Park Plaza
                                P.O. Box 570
                          Newark, New Jersey 07101-0570
                                 973-430-7000
                             http://www.pseg.com


Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the  preceding 12 months (or for such  shorter  period that the  registrant  was
required  to file  such  reports),  and  (2) has  been  subject  to such  filing
requirements for the past 90 days.

                                   Yes X     No

As of June 30, 2002,  Public Service Electric and Gas Company and had issued and
outstanding  132,450,344  shares of common stock,  without nominal or par value,
all of which were privately held,  beneficially  and of record by Public Service
Enterprise Group Incorporated.

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<PAGE>
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                     PUBLIC SERVICE ELECTRIC AND GAS COMPANY
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                                TABLE OF CONTENTS

                                                                         PAGE
                                                                         ----
PART I. FINANCIAL INFORMATION
-----------------------------

Item 1.  Financial Statements...........................................   1

Item 2.  Management's Discussion and Analysis of Financial Condition
         and Results of Operations......................................  11

Item 3.  Qualitative and Quantitative Disclosures About Market Risk.....  17


PART II. OTHER INFORMATION
--------------------------

Item 1.       Legal Proceedings.........................................  19

Item 5.       Other Information.........................................  19

Item 6.       Exhibits and Reports on Form 8-K..........................  21

Signature...............................................................  22



<PAGE>

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                     PUBLIC SERVICE ELECTRIC AND GAS COMPANY
================================================================================

                          PART I. FINANCIAL INFORMATION
                          -----------------------------
                          ITEM 1. FINANCIAL STATEMENTS


<PAGE>
<TABLE>
<CAPTION>

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


                                                                       For the Quarters Ended          For the Six Months Ended
                                                                              June 30,                         June 30,
                                                                    -----------------------------    ------------------------------
                                                                       2002             2001            2002              2001
                                                                    -----------     -------------    ------------     -------------
<S>                                                                     <C>               <C>         <C>             <C>
OPERATING REVENUES
   Electric Transmission and Distribution...................            924               959         $ 1,768         $   1,829
   Gas Distribution.........................................            306               352           1,121             1,434
                                                                    -----------     -------------    ------------     -------------
       Total Operating Revenues.............................          1,230             1,311           2,889             3,263
                                                                    -----------     -------------    ------------     -------------
OPERATING EXPENSES
   Electric Energy Costs....................................            569               558           1,101             1,111
   Gas Costs................................................            189               243             716             1,030
   Operation and Maintenance................................            233               242             482               492
   Depreciation and Amortization............................            100                91             198               163
   Taxes Other than Income Taxes............................             32                31              75                74
                                                                    -----------     -------------    ------------     -------------
       Total Operating Expenses.............................          1,123             1,165           2,572             2,870
                                                                    -----------     -------------    ------------     -------------
OPERATING INCOME                                                        107               146             317               393
Other Income................................................              6                24              11                94
Other Deductions............................................                               (1)             (1)               (2)
Interest Expense............................................           (102)             (112)           (203)             (228)
Preferred Securities Dividend Requirements of Subsidiaries..             (4)               (7)             (7)              (18)
                                                                    -----------     -------------    ------------     -------------
INCOME BEFORE INCOME TAXES..................................              7                50             117               239
Income Taxes................................................              1               (18)            (41)              (95)
                                                                    -----------     -------------    ------------     -------------
NET INCOME..................................................              8                32              76               144
Preferred Securities Dividend Requirements and Premium
   on Redemption............................................             (1)               (1)             (2)               (4)
                                                                    -----------     -------------    ------------     -------------
EARNINGS AVAILABLE TO PUBLIC SERVICE
   ENTERPRISE GROUP INCORPORATED............................        $     7         $      31        $     74         $     140
                                                                    ===========     =============    ============     =============

See Notes to Consolidated Financial Statements
</TABLE>


<PAGE>
<TABLE>
<CAPTION>
                    PUBLIC SERVICE ELECTRIC AND GAS COMPANY
                           CONSOLIDATED BALANCE SHEETS
                                     ASSETS
                              (Millions of Dollars)
                                   (Unaudited)



                                                                                       June 30,           December 31,
                                                                                         2002                 2001
                                                                                    ---------------      ----------------
<S>                                                                                         <C>          <C>
CURRENT ASSETS
   Cash and Cash Equivalents...............................................                 191          $        102
   Accounts Receivable:
     Customer Accounts Receivable..........................................                 505                   556
     Other Accounts Receivable.............................................                  55                    67
     Allowance for Doubtful Accounts.......................................                 (32)                  (38)
   Unbilled Revenues.......................................................                 181                   291
   Natural Gas.............................................................                  --                   415
   Materials and Supplies..................................................                  56                    50
   Prepayments.............................................................                 275                    40
   Energy Contracts........................................................                  --                    32
   Restricted Cash.........................................................                  13                    12
   Other...................................................................                  23                    22
                                                                                    ---------------      ----------------
     Total Current Assets..................................................               1,267                 1,549
                                                                                    ---------------      ----------------

PROPERTY, PLANT AND EQUIPMENT
   Electric................................................................               5,604                 5,501
   Gas ....................................................................               3,355                 3,284
   Other...................................................................                 390                   385
                                                                                    ---------------      ----------------
     Total.................................................................               9,349                 9,170
   Accumulated Depreciation and Amortization...............................              (3,478)               (3,329)
                                                                                    ---------------      ----------------
     Net Property, Plant and Equipment.....................................               5,871                 5,841
                                                                                    ---------------      ----------------

NONCURRENT ASSETS
   Regulatory Assets.......................................................               5,094                 5,247
   Long-Term Investments...................................................                 118                   112
   Other Special Funds.....................................................                 172                   130
   Other...................................................................                  75                    84
                                                                                    ---------------      ----------------
     Total Noncurrent Assets...............................................               5,459                 5,573
                                                                                    ---------------      ----------------
TOTAL ASSETS...............................................................              12,597                12,963
                                                                                     ==============       ===============

See Notes to Consolidated Financial Statements.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>
                     PUBLIC SERVICE ELECTRIC AND GAS COMPANY
                           CONSOLIDATED BALANCE SHEETS
                         LIABILITIES AND CAPITALIZATION
                              (Millions of Dollars)
                                   (Unaudited)



                                                                                      June 30,          December 31,
                                                                                        2002                2001
                                                                                   ---------------     ----------------
<S>                                                                                        <C>                  <C>
   CURRENT LIABILITIES
   Long-Term Debt Due Within One Year.....................................                 974                  668
   Accounts Payable.......................................................                 504                  642
   Energy Contracts.......................................................                  --                  169
   Accrued Taxes..........................................................                  37                   30
   Other..................................................................                 298                  277
                                                                                   ---------------     ----------------
     Total Current Liabilities............................................               1,813                1,786
                                                                                   ---------------     ----------------

NONCURRENT LIABILITIES
   Deferred Income Taxes and ITC..........................................               2,542                2,551
   Regulatory Liabilities.................................................                 409                  373
   OPEB Costs.............................................................                 483                  466
   Other..................................................................                 202                  205
                                                                                   ---------------     ----------------
     Total Noncurrent Liabilities.........................................               3,636                3,595
                                                                                   ---------------     ----------------

CAPITALIZATION

   LONG-TERM DEBT
     Long-Term Debt.......................................................               2,327                2,626
     Securitization Debt..................................................               2,293                2,351
                                                                                   ---------------     ----------------
       Total Long-Term Debt...............................................               4,620                4,977

   PREFERRED SECURITIES
     Preferred Stock Without Mandatory Redemption.........................                  80                   80
     Subsidiaries' Preferred Securities:
     Guaranteed Preferred Beneficial Interest in Subordinated
       Debentures.........................................................                 155                  155
                                                                                   ---------------     ----------------
       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....................................................                 417                  493
     Accumulated Other Comprehensive Loss.................................                  (2)                  (1)
                                                                                   ---------------     ----------------
       Total Common Stockholder's Equity..................................               2,293                2,370
                                                                                   ---------------     ----------------
         Total Capitalization.............................................               7,148                7,582
                                                                                   ---------------     ----------------
TOTAL LIABILITIES AND CAPITALIZATION......................................              12,597               12,963
                                                                                    ==============      ===============

See Notes to Consolidated Financial Statements
</TABLE>


<PAGE>
<TABLE>
<CAPTION>
                     PUBLIC SERVICE ELECTRIC AND GAS COMPANY
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                              (Millions of Dollars)
                                   (Unaudited)

                                                                                       For the Six Months Ended
                                                                                               June 30,
                                                                                 -------------------------------------
                                                                                     2002                 2001
                                                                                 --------------     ------------------
<S>                                                                               <C>                <C>
   CASH FLOWS FROM OPERATING ACTIVITIES
   Net income.................................................................    $      76          $         144
   Adjustments to reconcile net income to net cash flows from
     operating activities:
   Depreciation and Amortization..............................................          198                    163
   Amortization of Deferred Gas Costs.........................................           17                     --
   Provision for Deferred Income Taxes and ITC................................          (26)                    21
   Other Non-Cash Charges.....................................................           15                     19
   Net Changes in Certain Current Assets and Liabilities:
     Accounts Receivable and Unbilled Revenues................................          167                    206
     Natural Gas..............................................................          415                     18
     Prepayments..............................................................         (235)                  (228)
     Restricted Cash..........................................................           (1)                   (62)
     Accounts Payable.........................................................         (138)                  (206)
     Accrued Taxes............................................................            7                     (4)
     Other Current Assets and Liabilities.....................................           --                     57
   Overrecovery of Electric Energy Costs and Market Transition Charge (MTC)...           93                     13
   Underrecovery of Gas Costs.................................................          (92)                  (111)
   Other......................................................................           54                     14
                                                                                 --------------     ------------------
     Net Cash Provided By Operating Activities................................          550                     44
                                                                                 --------------     ------------------

CASH FLOWS FROM INVESTING ACTIVITIES
   Additions to Property, Plant and Equipment.................................         (196)                  (172)
   Contributions to Other Special Funds.......................................          (63)                   (30)
   Other......................................................................            1                     (6)
                                                                                 --------------     ------------------
     Net Cash Used in Investing Activities....................................         (258)                  (208)
                                                                                 --------------     ------------------

CASH FLOWS FROM FINANCING ACTIVITIES
   Net Change in Short-Term Debt..............................................           --                 (1,487)
   Issuance of Long-Term Debt.................................................           --                  2,525
   Deferred Issuance Costs....................................................           --                   (201)
   Redemption/Purchase of Long-Term Debt......................................          (51)                  (299)
   Collection of Note Receivable - Affiliated Company.........................           --                  2,786
   Redemption of Preferred Securities.........................................           --                   (448)
   Return of Capital..........................................................           --                 (2,265)
   Cash Dividends Paid on Common Stock........................................         (150)                  (112)
   Other......................................................................           (2)                    (4)
                                                                                 --------------     ------------------
     Net Cash Provided By (Used) in Financing Activities......................         (203)                   495
                                                                                 --------------     ------------------
Net Change in Cash and Cash Equivalents.......................................           89                    331
Cash and Cash Equivalents at Beginning of Period..............................          102                     39
                                                                                 --------------     ------------------
Cash and Cash Equivalents at End of Period....................................          191         $          370
                                                                                 ==============      =================


Income Taxes Paid.............................................................          117         $          192
Interest Paid.................................................................          202         $          152

See Notes to Consolidated Financial Statements
</TABLE>

<PAGE>
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                     PUBLIC SERVICE ELECTRIC AND GAS COMPANY
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                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                   (UNAUDITED)

Note 1. Organization and Basis of Presentation

Organization

Unless the context otherwise indicates, all references to "PSE&G," "we," "us" or
"our"  herein  means  Public  Service  Electric  & Gas  Company,  a  New  Jersey
corporation with its principal  executive offices at 80 Park Plaza,  Newark, New
Jersey 07102 and its consolidated subsidiaries. We are a wholly-owned subsidiary
of Public  Service  Enterprise  Group  Incorporated  (PSEG) and are an operating
public utility providing electric transmission and electric and gas distribution
service in certain  areas  within the State of New Jersey.  PSEG owns all of our
common stock.

Basis of Presentation

The financial  statements  included  herein have been  prepared  pursuant to the
rules and regulations of the Securities and Exchange  Commission (SEC).  Certain
information  and note  disclosures  normally  included in  financial  statements
prepared in accordance with generally accepted  accounting  principles have been
condensed or omitted  pursuant to such rules and  regulations.  However,  in the
opinion of  management,  the  disclosures  are adequate to make the  information
presented not misleading.  These Consolidated Financial Statements  (Statements)
and Notes to  Consolidated  Financial  Statements  (Notes) update and supplement
matters  discussed in our 2001 Annual  Report on Form 10-K and should be read in
conjunction with those Notes.

The unaudited  financial  information  furnished  reflects all adjustments which
are, in the opinion of management, necessary to fairly state the results for the
interim periods presented. The year-end Consolidated Balance Sheets were derived
from the audited  Consolidated  Financial Statements included in our 2001 Annual
Report on Form 10-K.  Certain  reclassifications  of prior period data have been
made to conform with the current presentation.

Note 2. Accounting Matters

On January 1, 2002,  we adopted  Statement  of  Financial  Accounting  Standards
(SFAS) No. 142,  "Goodwill and Other  Intangible  Assets" (SFAS 142). Under SFAS
142,  goodwill is considered a nonamortizable  asset and is subject to an annual
review  for  impairment  and an  interim  review  when  required  by  events  or
circumstances.  We currently do not have any goodwill or other intangible assets
on our balance sheet.  Therefore,  there was no effect on our financial position
or results of operations as a result of adopting this standard.

On January 1, 2002 we adopted SFAS 144. On adoption,  the impact of SFAS 144 did
not have an effect on our  financial  position or results of  operations.  Under
SFAS 144,  long-lived  assets to be  disposed  of are  measured  at the lower of
carrying amount or fair value less costs to sell,  whether reported in continued
operations  or in  discontinued  operations.  Also under SFAS 144,  discontinued
operations will no longer be measured at net realizable value or include amounts
for operating  losses that have not yet occurred.  Under SFAS 144,  discontinued
operations  will be measured at fair value,  less costs to sell.  Also, as under
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed  of" (SFAS  121),  a  long-lived  asset must be tested for
impairment  whenever  events  or  changes  in  circumstances  indicate  that its
carrying amount may be impaired.
<PAGE>
In July 2001, the Financial  Accounting  Standards  Board (FASB) issued SFAS No.
143,  "Accounting for Asset Retirement  Obligations" (SFAS 143). Under SFAS 143,
the fair  value of a  liability  for an asset  retirement  obligation  should be
recorded in the period in which it is created  with an  offsetting  amount to an
asset. Upon settlement of the liability, an entity either settles the obligation
for its recorded  amount or incurs a gain or loss upon  settlement.  SFAS 143 is
effective  for fiscal  years  beginning  after June 15, 2002.  We are  currently
evaluating  the effect of this  guidance  and cannot  predict  the impact on our
financial  position  or  results  of  operations.  However,  such  impact may be
material to the  classification  of items on our balance sheet.  We currently do
not expect any income statement effect due to the adoption of this statement.

Note 3. Regulatory Assets and Liabilities

We prepare our financial  statements in accordance  with the  provisions of SFAS
71,  "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) which
differs  in  certain  respects  from the  application  of GAAP by  non-regulated
businesses.  In general,  SFAS 71 recognizes that accounting for  rate-regulated
enterprises  should reflect the economic  effects of regulation.  As a result, a
regulated  utility is required to defer the  recognition  of costs (a regulatory
asset) or the  recognition  of  obligations  (a  regulatory  liability) if it is
probable that,  through the rate-making  process,  there will be a corresponding
increase or decrease in future  rates.  Accordingly,  we have  deferred  certain
costs,  which will be amortized  over various  future  periods.  These costs are
deferred based on rate orders issued by the New Jersey Board of Public Utilities
(BPU) or the  Federal  Energy  Regulatory  Commission  (FERC)  and our  recovery
experience with prior rate cases. As of June 30, 2002,  approximately 87% of our
regulatory assets were deferred based on written rate orders.  Regulatory assets
recorded on a basis other than by an issued  rate order have less  certainty  of
recovery  since they can be disallowed in the future by regulatory  authorities.
However,  we have experienced no material  disallowances in the past. We believe
that all of our regulatory assets are probable of recovery.

At June 30, 2002 and  December  31,  2001,  respectively,  we had  deferred  the
following regulatory assets and liabilities on the Consolidated Balance Sheets:
<TABLE>
<CAPTION>

                                                                              June 30,          December 31,
                                                                                2002                2001
                                                                           --------------     -----------------
                                                                                 (Millions of Dollars)
<S>                                                                              <C>                   <C>
    Regulatory Assets
    Stranded Costs To Be Recovered..................................             $4,009                $4,105
    SFAS 109 Income Taxes...........................................                313                   302
    OPEB Costs......................................................                203                   212
    Societal Benefits Charges (SBC).................................                 --                     4
    Manufactured Gas Plant Remediation Costs........................                 87                    87
    Unamortized Loss on Reacquired Debt and Debt Expense............                 88                    92
    Underrecovered Gas Costs........................................                195                   120
    Unrealized Losses on Gas Contracts..............................                 --                   137
    Other...........................................................                199                   188
                                                                           --------------     -----------------
          Total Regulatory Assets...................................             $5,094                $5,247
                                                                           ==============     =================

    Regulatory Liabilities
    Excess Depreciation Reserve.....................................               $245                  $319
    Non-Utility Generation Transition Charge (NTC)..................                125                    48
    SBC.............................................................                 28                    --
    Other...........................................................                 11                     6
                                                                           --------------     -----------------
          Total Regulatory Liabilities..............................               $409                  $373
                                                                           ==============     =================
</TABLE>

All  regulatory  assets and  liabilities  are excluded from our rate base unless
otherwise noted in the descriptions below.

Stranded Costs To Be Recovered: This reflects the deferred costs to be recovered
by the securitization transition charge, which was authorized by the BPU's Final
Order and Finance  Order in our  deregulation  proceedings.  These  orders are a
matter of public  record and are  available  at the BPU.  These costs  primarily
relate to the  write-down  of our fixed assets in 1999 that was  required  under
SFAS No. 121,  "Accounting  for Long-Lived  Assets and  Long-Lived  Assets to be
Disposed of" (SFAS 121). PSE&G Transition Funding LLC (Transition Funding),  our
wholly-owned  subsidiary,  issued transition bonds to recover these costs net of
deferred taxes.  Accordingly,  this regulatory asset is offset by securitization
debt and a deferred tax liability.  Funds collected  through the  securitization
transition  charge  will be  used to make  the  future  interest  and  principle
payments on the transition bonds. This amount will be recovered over the life of
the transition bonds, which is expected to conclude in December 2015.

SFAS 109 Income Taxes:  This amount  represents  the portion of deferred  income
taxes that will be  recovered  through  future  rates,  based  upon  established
regulatory practices,  which permit the recovery of current taxes.  Accordingly,
this  regulatory  asset is offset by a deferred tax liability and is expected to
be recovered  without  interest over the period the underlying  book-tax  timing
differences reverse and become current taxes.

OPEB Costs: Includes costs associated with adoption of SFAS No. 106, "Employers'
Accounting for Benefits Other Than Pensions" (SFAS 106),  which were deferred in
accordance  with EITF Issue 92-12,  "Accounting for OPEB Costs by Rate Regulated
Enterprises"  (EITF 92-12).  Prior to the adoption of SFAS 106,  post-retirement
benefits  costs were  recognized  on a cash basis.  SFAS 106 required that these
costs be accrued as the benefits  were  earned.  Accordingly  a liability  and a
regulatory   asset  were  recorded  for  the  total   benefits   earned  at  the
implementation  date.  Beginning  January  1,  1998,  we began to  recover  this
regulatory asset over 15 years without interest.

SBC:  The SBC  includes  costs  related  to our  electric  and gas  distribution
business as follows:  1) social  programs  which include the  universal  service
fund;  2)  nuclear  plant  decommissioning;  3)  demand  side  management  (DSM)
programs;  4)  manufactured  gas plant  remediation  expenditures;  5)  consumer
education;  6) Under and  overrecovered  electric bad debt expenses;  and 7) MTC
overrecovery.  These costs are recovered/refunded  with interest. The SBC clause
will be revised at the end of the transition period on August 1, 2003.

Manufactured  Gas  Plant   Remediation   Costs:   Represents   estimated  future
environmental  investigation  and  remediation  expenditures  (net of  insurance
recoveries),  which are  probable of recovery in future  rates  through the SBC.
This  amount will be  transferred  to the SBC  regulatory  asset when the actual
expenditures  are made.  Interest  is not  recoverable  on these costs until the
actual  expenditures  are made. This regulatory  asset is offset by a noncurrent
liability on the balance sheet.

Unamortized  Loss on Reacquired Debt and Debt Expense:  Represents bond issuance
costs, premiums,  discounts and losses on reacquired long-term debt. These costs
are amortized with interest,  over the remaining life of the reacquired  debt or
over the life of the new debt, if refinanced.

Underrecovered Gas Costs:  Represents gas costs in excess of or below the amount
included  in  rates  and   probable  of  recovery  in  the  future.   Generally,
underrecovered gas costs do not accrue interest while overrecovered gas costs do
accrue  interest.  The LGAC rate is  normally  adjusted  on an annual  basis.  A
portion of the current  underrecovery,  $117 million at June 30, 2002,  is being
recovered  over an extended  period  through  September  2004. We are recovering
interest  during this  extended  period.  The  remaining  portion of the current
underrecovery,  $78 million, is expected to be recovered  subsequent to our next
gas rate proceeding, the time of which is not currently known.

Unrealized Losses on Gas Contracts:  This represents the recoverable  portion of
unrealized   losses   associated  with  contracts  used  in  the  company's  gas
distribution business.  This asset is offset by the net energy contracts payable
on the balance sheet.  Subsequent to the gas contract transfer to PSEG Power LLC
(Power),  an unregulated  affiliate,  in May 2002, we no longer enter into these
contracts.

Other Regulatory Assets:  Includes  Decontamination  and  Decommissioning  Costs
which are offset by a noncurrent liability on the balance sheet and are expected
to be collected without interest until December 2007; Plant and Regulatory Study
Costs are expected to be recovered  without interest until December 2021; Repair
Allowance Tax Deficiencies and Interest;  Oil and Gas Property  Write-Down which
is expected to be recovered without interest until December 2002;  restructuring
costs that will be recovered with or without interest,  which will be determined
at our upcoming  electric  rate case,  from August 1, 2003 through July 31, 2007
and recovery of costs  related to Transition  Funding's  interest rate swap that
will be  recovered  without  interest  over  the  life of  Transition  Funding's
transition bonds,  which is expected to conclude in December 2015. This asset is
offset by a derivative liability on the balance sheet.

Excess  Depreciation  Reserve:  As required by a BPU rate order,  we reduced our
depreciation  reserve for our electric  distribution  assets by $569 million and
recorded such amount as a regulatory  liability to be amortized  over the period
from January 1, 2000 to July 31, 2003.

NTC:  This clause was  established  to account for above market costs related to
non-utility  generation  (NUG)  contracts.  NUG  contract  costs are  charged to
expense and proceeds  from the sale of the energy and capacity  purchased  under
these NUG  contracts are also credited to expense.  The  difference  between the
collection of NTC revenue and the related expense is deferred. Costs or benefits
associated with the restructuring of these contracts are deferred as well. These
amounts are expected to be returned to customers with  interest.  The NTC clause
will be revised at the end of the  transition  period on August 1, 2003. The NTC
balance,  including the anticipated deferral of the difference between the Basic
Generation  Service (BGS) payments to suppliers and collections  from customers,
are expected to be addressed  together with the new electric  distribution  base
rates and incorporated into rates on August 1, 2003.

Other  Regulatory  Liabilities:  This  includes  the  following:  1) Interest on
amounts collected from customers that are used to fund incentives for choosing a
third  party gas  supplier;  2)  Interest on amounts  collected  from  customers
resulting  from the Energy Tax Reform Act that are currently  being used to fund
customer  education  discounts  approved by the BPU; 3) Amounts  collected  from
customers  in  order  for  Transition  Funding  to  obtain a AAA  rating  on its
transition bonds and 4) Amounts that will be returned to Firm Gas customers with
interest.

Note 4. Commitments and Contingent Liabilities

Hazardous Waste

The New  Jersey  Department  of  Environmental  Protection  (NJDEP)  regulations
concerning site investigation and remediation  require an ecological  evaluation
of  potential  injuries  to  natural  resources  in  connection  with a remedial
investigation  of  contaminated  sites.  The  NJDEP is  presently  working  with
industry  to  develop  procedures  for  implementing  these  regulations.  These
regulations may substantially increase the costs of remedial  investigations and
remediations,  where necessary,  particularly at sites situated on surface water
bodies.  We  and  our  predecessor   companies  owned  and/or  operated  certain
facilities situated on surface water bodies,  certain of which are currently the
subject of remedial  activities.  The financial  impact of these  regulations on
these  projects  is not  currently  estimable.  We do not  anticipate  that  the
compliance  with these  regulations  will have a material  adverse effect on our
financial position, results of operations or net cash flows.

Manufactured Gas Plant Remediation Program

We are currently working with the NJDEP under a program (Remediation Program) to
assess, investigate and, if necessary, remediate environmental conditions at our
former  manufactured  gas  plant  sites  (MGPs).  To date,  38 sites  have  been
identified.  The Remediation Program is periodically  reviewed and revised by us
based on regulatory  requirements,  experience with the Remediation  Program and
available  remediation  technologies.  The  long-term  costs of the  Remediation
Program cannot be reasonably estimated, but experience to date indicates that at
least $20  million  per year could be  incurred  over a period of about 30 years
since  inception  of the  program  in 1988 and that the  overall  cost  could be
material. The costs for this remediation effort are recovered through the SBC.

At June 30, 2002 and December 31, 2001, our estimated  liability for remediation
costs through 2004  aggregated $87 million.  Expenditures  beyond 2004 cannot be
reasonably estimated.

Passaic River Site

The United States  Environmental  Protection  Agency (EPA) has determined that a
six mile  stretch of the  Passaic  River in the area of Newark,  New Jersey is a
"facility"  within  the  meaning of that term  under the  Federal  Comprehensive
Environmental  Response,  Compensation  and  Liability  Act of 1980 and that, to
date, at least thirteen  corporations,  including us, may be potentially  liable
for performing  required  remedial  actions to address  potential  environmental
pollution in the Passaic River  "facility."  We and certain of our  predecessors
conducted  industrial  operations  at properties on that six mile stretch of the
Passaic River. The operations include one operating electric generating station,
one former  generating  station,  and four  former  MGPs.  Our costs to clean up
former  MGPs are  recoverable  from  utility  customers  under the SBC.  We have
contracted to sell the site of the former  generating  station,  contingent upon
approval by state regulatory  agencies,  to a third party that would release and
indemnify us for claims  arising out of the site. We cannot predict what action,
if any,  the EPA or any third  party may take  against  us with  respect to this
matter,  or in such event,  what costs we may incur to address any such  claims.
However, such costs may be material.

Note 5. Financial Instruments and Risk Management

Our operations are exposed to market risks from changes in commodity  prices and
interest  rates  that could  affect our  results  of  operations  and  financial
conditions.  We manage our exposure to these  market  risks  through our regular
operating and financing  activities  and, when deemed  appropriate,  hedge these
risks through the use of derivative financial instruments. We use the term hedge
to mean a strategy  designed  to manage  risks of  volatility  in prices or rate
movements on certain  assets,  liabilities  or anticipated  transactions  and by
creating a relationship  in which gains or losses on derivative  instruments are
expected to  counterbalance  the losses or gains on the assets,  liabilities  or
anticipated  transactions  exposed  to  such  market  risks.  We use  derivative
instruments  as risk  management  tools  consistent  with our business plans and
prudent business practices and not for speculative purposes.
<PAGE>
Fair Value of Financial Instruments

The estimated fair values were determined using the market  quotations or values
of instruments  with similar terms,  credit  ratings,  remaining  maturities and
redemptions at June 30, 2002 and December 31, 2001, respectively.
<TABLE>
<CAPTION>
                                                                  June 30, 2002              December 31, 2001
                                                             -------------------------   ---------------------------
                                                              Carrying       Fair         Carrying         Fair
                                                               Amount        Value         Amount          Value
                                                             ------------  -----------   ------------    -----------
                                                                             (Millions of Dollars)
<S>                                                             <C>           <C>             <C>            <C>
Long-Term Debt:
     PSE&G.................................................    $3,301        $3,351          $3,294         $3,290
     Transition Funding....................................     2,293         2,536           2,351          2,575
Preferred Securities Subject to Mandatory Redemption:
     Monthly Guaranteed Preferred Beneficial Interest in
        PSE&G's Subordinated Debentures....................        60            61              60             60
     Quarterly Guaranteed Preferred Beneficial Interest in
        PSE&G's Subordinated Debentures....................        95            96              95             96
</TABLE>

Commodity-Related Instruments

Prior to May 1, 2002,  we used natural gas futures and swaps to reduce  exposure
to price  fluctuations  in natural gas from factors such as weather,  changes in
demand and changes in supply to manage the price risk associated with gas supply
to our customers.  These  instruments,  in conjunction  with physical gas supply
contracts,  were designed to cover  estimated gas customer  commitments.  We had
entered  into 330 MMBTU of gas  futures,  swaps and options to hedge  forecasted
requirements as of December 31, 2001. As of December 31, 2001, the fair value of
those  instruments was $(137) million,  with a maximum term of approximately one
year. We utilized derivatives to hedge our gas purchasing activities which, when
realized,  were recoverable  through our Levelized Gas Adjustment Clause (LGAC).
Accordingly,  the offset to the change in fair  value of these  derivatives  was
recorded as a regulatory asset or liability.

As a result of the gas contract  transfer that was  effective  May 1, 2002,  the
price risk  relating to gas  purchases was  transferred  to Power.  As a result,
after that date, we are no longer utilizing these derivative  instruments in our
gas distribution  business. Our gas supply is now obtained through the Basic Gas
Supply  Service  (BGS)  contract  with  Power.   See  Note  10.  Related  Party
Transactions for further discussion.

<PAGE>
Interest Rates

We are subject to the risk of fluctuating interest rates in the normal course of
business.  Our policy is to manage  interest  rate risk through the use of fixed
rate debt,  floating  rate debt and interest  rate swaps.  We currently  have no
floating rate debt outstanding that is exposed to interest rate risk.

Transition  Funding has entered into an interest  rate swap on its sole class of
floating rate  transition  bonds.  The notional amount of the interest rate swap
was  approximately  $497  million.  The  interest  rate swap is  indexed  to the
three-month   LIBOR  rate.  The  fair  value  of  the  interest  rate  swap  was
approximately $(32) million as of June 30, 2002 and $(18) million as of December
31, 2001 and was recorded as a derivative  liability,  with an offsetting amount
recorded as a regulatory  asset on the Consolidated  Balance Sheet.  This amount
will vary over time as a result of changes in market conditions.

Note 6. Income Taxes

A tax  (benefit)  expense  has  been  recorded  for the  results  of  continuing
operations. An analysis of that (benefit) expense is as follows:
<TABLE>
<CAPTION>

                                                                     Quarter Ended              Six Months Ended
                                                                       June 30,                     June 30,
                                                                -------------------------    ------------------------
                                                                  2002            2001           2002          2001
                                                                -----------    ----------    -----------    ---------

<S>                                                                  <C>         <C>           <C>             <C>
Pre-Tax Income...........................................            $7          $ 50          $117           $239

Tax Computed at the Federal Statutory Rate at 35%........             2            18            41             84

Increases (decreases) from Federal statutory rate
 attributable to:
    State Income Taxes after Federal Benefit.............             1             4            10             18
    Plant Related Items..................................            (3)           (5)           (7)           (10)
    Other................................................            (1)            1            (3)             3
                                                                -----------   ----------   ------------    ---------
Total Income Tax Expense.................................           $(1)          $18           $41            $95
                                                                -----------   ----------   ------------    ---------

      Effective Income Tax Rate..........................         (14.3%)        36.0%         35.0%          39.7%
</TABLE>

For  the  quarter  ended  June  30,  2002,  regulatory  accounting  differences,
primarily  plant-related  items, are  proportionally  higher relative to pre-tax
income resulting in a relatively low effective tax rate.
<PAGE>
Note 7. Financial Information by Business Segments

Following the transfer of our generation-related assets to Power in August 2000,
we continue to own and operate our transmission and distribution  (T&D) business
as our only reportable segment.

Note 8. Comprehensive Income

Comprehensive Income, Net of Tax:
<TABLE>
<CAPTION>
                                                                         Quarter Ended             Six Months Ended
                                                                            June 30,                   June 30,
                                                                     ------------------------    -----------------------
                                                                      2002           2001         2002          2001
                                                                     ---------     ----------    ---------    ----------
<S>                                                                    <C>           <C>           <C>          <C>
Net Income....................................................         $8            $32           $76          $144
Pension Adjustment, Net of Tax................................         --              2            (1)            2
                                                                     ---------     ----------    ---------    ----------
Comprehensive Income..........................................         $8            $34           $75          $146
                                                                     =========     ==========    =========    ==========
</TABLE>

Note 9. Other Income
<TABLE>
<CAPTION>

                                                                         Quarter Ended              Six Months Ended
                                                                           June 30,                     June 30,
                                                                     ----------------------      -----------------------
                                                                       2002         2001           2002         2001
                                                                     ---------     --------      ---------    ----------
                                                                                   (Millions of Dollars)
<S>                                                                    <C>           <C>             <C>          <C>
Other Income
    Interest Income...........................................         $5            $21             $9           $90
    Gain on Disposition of Property...........................          1              3              1             3
    Other.....................................................         --             --              1             1
                                                                     ---------     --------      ---------    ----------
Total Other Income............................................         $6            $24            $11           $94
                                                                     =========     ========      =========    ==========
</TABLE>
Note 10. Related-Party Transactions

In August 2000,  we  transferred  our electric  generation  business to Power in
exchange for a $2.786 billion  Promissory Note.  Interest on the Promissory Note
was payable at an annual rate of 14.23%,  which represented our weighted average
cost of capital.  For the period from  January 1, 2001 to January 31,  2001,  we
recorded interest income of approximately $34 million relating to the Promissory
Note. Power repaid the Promissory Note on January 31, 2001.

In addition, on January 31, 2001, we loaned $1.084 billion to PSEG at 14.23% per
annum and recorded  interest income of  approximately $6 million and $33 million
relating  to the  loan for the  quarter  and six  months  ended  June  30,  2001
respectively.  PSEG repaid the loan on April 16, 2001. We also  returned  $2.265
billion of  capital to PSEG on January  31,  2001  utilizing  proceeds  from the
$2.525 billion securitization  transaction and the generation asset transfer, as
required by the BPU's Final Order, as part of our recapitalization.

<PAGE>
Effective with the transfer of the electric generation  business,  Power charges
us for the Market  Transition  Charge (MTC) and the energy and capacity provided
to  meet  our  BGS  requirements.  The  MTC  was  authorized  by  the  BPU as an
opportunity  to recover  up to $540  million  (net of tax) of our  unsecuritized
generation-related  stranded costs on a net present value basis.  The amounts we
recover  from  customers  through the MTC are paid to Power,  thus this does not
impact our  earnings.  For the  quarters  ended June 30, 2002 and 2001,  we were
charged by Power approximately $488 million and $475 million,  respectively, for
the MTC and BGS.  For the six  months  ended  June 30,  2002 and  2001,  we were
charged by Power approximately $948 million and $938 million,  respectively, for
the MTC and BGS. As of June 30, 2002 and December 31, 2001, our payable to Power
relating to these costs was approximately $179 million and $159 million. For the
quarters ended June 30, 2002 and 2001, respectively, we sold energy and capacity
to Power at the market price of approximately $34 million and $36 million, which
we purchased  under various NUG contracts at costs above market prices.  For the
six months ended June 30, 2002 and 2001, these sales totaled $63 million and $80
million, respectively. As of June 30, 2002 and December 31, 2001, our receivable
related  to these  purchases  was  approximately  $13  million  and $7  million,
respectively.  As a result  of the Final  Order,  we have  established  a NTC to
recover the above market costs related to these NUG  contracts.  The  difference
between  our costs and  recovery  of costs  through  the NTC and sales to Power,
which are priced at the  locational  marginal  price (LMP) set by PJM for energy
and at wholesale  market prices for capacity,  is deferred as a regulatory asset
or liability.

Effective May 1, 2002, we transferred our gas supply contracts and gas inventory
to Power for  approximately  $183  million.  On the same date we entered  into a
requirements  contract  with Power under which Power will provide the  delivered
gas supply  services  needed to meet our BGSS.  The contract term ends March 31,
2004  with a  three-year  renewal  option.  As  part  of the  agreement,  we are
providing  Power the use of our  peaking  shaving  facilities  at cost.  The net
billings   under  the  contract  for  the  quarter  ended  June  30,  2002  were
approximately $96 million. Our net payable as of June 30, 2002 was approximately
$54 million.

PSEG Services Corporation provides and bills administrative  services to us on a
monthly basis. Our costs related to such service  amounted to approximately  $51
million  and $61  million  for the  quarters  ended  June  30,  2002  and  2001,
respectively.  These costs  totaled  $103  million and $116  million for the six
months  ended  June 30,  2002 and 2001,  respectively.  As of June 30,  2002 and
December  31, 2001,  our payable  related to these costs was  approximately  $19
million and $25 million, respectively.
<PAGE>
================================================================================
                     PUBLIC SERVICE ELECTRIC AND GAS COMPANY
================================================================================

                 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
                  FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Unless the context otherwise indicates, all references to "PSE&G," "we," "us" or
"our" herein means Public Service Electric & Gas Company  (PSE&G),  a New Jersey
corporation with its principal  executive offices at 80 Park Plaza,  Newark, New
Jersey 07102.  This  discussion  makes reference to our  Consolidated  Financial
Statements and related Notes to the Consolidated  Financial  Statements  (Notes)
and should be read in conjunction with such statements and notes.

Following are the significant changes in or additions to information reported in
our 2001 Annual Report on Form 10-K and March 31, 2002 Quarterly  Report on Form
10-Q  affecting  the  consolidated   financial  condition  and  the  results  of
operations  of  our  subsidiaries   and  us.  This  discussion   refers  to  our
Consolidated Financial Statements (Statements) and related Notes to Consolidated
Financial  Statements  (Notes)  and  should  be read in  conjunction  with  such
Statements and Notes.

Overview of the Quarter and Six Months Ended June 30, 2002 and Future Outlook

For the quarter ended June 30, 2002, net income  decreased $24 million or 75% as
compared to the  quarter  ended June 30, 2001  primarily  due to lower  electric
revenue and interest  income compared to the prior period,  partially  offset by
increased gas base rates and lower  interest and income tax expense due to lower
pre-tax  income.  The lower electric  revenue that impacted  earnings  primarily
related  to  demand  side  management  (DSM),  distribution  sales  volumes  and
miscellaneous  revenues.  For further  discussion,  see the Results of Operation
section.

For the six months ended June 30, 2002, net income  decreased $68 million or 47%
as compared to the six months  ended June 30,  2001  primarily  due to lower gas
sales volumes as a result of the warmer  weather in early 2002,  lower  electric
revenue and interest  income  compared to the prior  period.  This was partially
offset by increased gas base rates and lower interest and income tax expense due
to lower pre-tax  income.  The lower  electric  revenue that  impacted  earnings
primarily related to DSM, distribution sales volumes and miscellaneous revenues.
For further discussion, see the Results of Operation section.

Our cash position  increased $89 million from December 31, 2001 to June 30, 2002
due primarily to $550 million of operating  cash inflows  offset by $258 million
and $203  million of cash  outflows  for  investing  and  financing  activities,
respectively.  Our operating cash inflows were primarily due to the gas contract
transfer  to  Power,  the  restructuring  of our  non-utility  generation  (NUG)
contract  with El Paso  Merchant  Energy,  and cash  earnings  during the period
offset by prepayments of taxes. Our investing cash outflows related primarily to
construction expenditures.  Our financing cash outflows related primarily to the
redemption of the Class A-1 series of PSE&G Transition Funding LLC's (Transition
Funding) transition bonds and cash dividends paid on common and preferred stock.

On June 5, 2002 we amended our NUG contract with El Paso Merchant Energy.  Under
federal law, we and other  utilities  were required to enter into  long-term NUG
contracts  with  cogeneration  facilities.  We sell the  electricity we purchase
under these  contracts to Power at the  Locational  Marginal  Price (LMP) in the
Pennsylvania-New  Jersey-Maryland  Power Pool (PJM). Any difference  between the
amounts we pay under the NUG  Contracts  and the amount we recover  through  the
Non-Utility  Generation Transition Charge (NTC) and sales at LMP are deferred as
a regulatory asset or liability.  Under the amended  contract,  we received $102
million in return  for  allowing  El Paso  Merchant  Energy to provide  electric
energy and capacity from the open market,  in addition to their existing  plant.
This amount will be passed back to customers through the NTC and was recorded as
a regulatory liability.

Effective May 1, 2002 we transferred our gas supply  contracts and gas inventory
to Power for  approximately  $183 million.  We received $149 million in cash and
Power assumed $34 million of liabilities relating to our commodity contracts. On
the same date,  we entered into a  requirements  contract with Power under which
Power will provide the  delivered gas supply  services  needed to meet our Basic
Gas  Supply  Service  (BGSS).  The  contract  term ends  March  31,  2004 with a
three-year renewal option. As part of the agreement,  we are providing Power the
use of our peaking shaving facilities at cost.

Under  the  terms  of the  contract,  Power  provides  gas  for  Commercial  and
Industrial BGSS customers at market based pricing which is passed on directly to
the  customers.  Gas for  Residential  BGSS customers is priced at Power's cost,
which  includes the cost of any hedging  arrangements.  We defer the  difference
between that cost and the amount  included in customer rates for future recovery
or return under our Levelized Gas Adjustment Charge (LGAC).

On May 1,  2002,  the New  Jersey  Ratepayer  Advocate  filed a  motion  for the
reconsideration  of the BPU's  approval of the gas  contract  transfer.  We have
opposed this motion and this matter is currently pending before the BPU.

For the quarter and six month ended June 30, 2002, we deferred  approximately $8
million and $16 million of revenues,  respectively,  due to overcollections from
the Market Transition Charge (MTC).  These amounts will be refunded to customers
with interest  through the societal  benefits charge (SBC)  beginning  August 1,
2003.  Refer  to  the  Critical   Accounting  Policies  section  for  additional
information regarding the MTC.

On May 24,  2002,  we filed an electric  rate case with the New Jersey  Board of
Public Utilities (BPU). In this filing, we requested an annual $250 million rate
increase for our electric  distribution  business.  The proposed  rate  increase
includes $187 million of increased  revenues relating to a $1.7 billion increase
in our rate base,  which is primarily due to the investment that we have made in
our electric distribution  facilities since the last electric rate case in 1992;
$18  million in higher  depreciation  rates and $45  million to recover  various
other  expenses,  such as wages,  fringe  benefits,  and the need to enhance the
security and  reliability  of the electric  distribution  system.  The requested
increase  proposes  a  maximum  return on  equity  of  11.75%  for our  electric
distribution business.

Assuming  current cost levels and a normal  business  environment,  the proposed
rate increase would significantly  impact our earnings and operating cash flows.
The  non-depreciation  portion of the rate increase  ($232 million) would have a
positive  effect on our  earnings and  operating  cash flows.  The  depreciation
portion of the rate increase ($18 million) would have no impact on our earnings,
as the  increased  operating  cash flows would be offset by higher  depreciation
charges.

In accordance with BPU'S Final Order,  which  implemented  parts of New Jersey's
Electric Discount and Competition Act, we were required to reduce electric rates
in four steps totaling 13.9% during the four year  transition  period.  The last
step, a 4.9% decrease, will take effect August 1, 2002.

If approved,  the proposed rate increase would be effective  August 1, 2003, the
end of the  transition  period.  While the proposed rate increase would increase
electric  distribution  rates by 12.8% from the July 31, 2003 level,  rates will
remain 2.6% lower than the levels in April  1999,  when the BPU issued its Final
Order.  We cannot  predict the outcome of these rate  proceedings at the current
time.

Various  cost-cutting  initiatives  recently put in place are expected to offset
lower revenues from our gas  distribution  business due to the warmer weather in
2002, and as a result, we have affirmed our projected  earnings for the year. We
currently  expect to earn  between  $175  million to $185 million for the twelve
months ending December 31, 2002. Our future success will be dependent,  in part,
on our ability to obtain a  successful  outcome to the recently  filed  electric
rate case,  our ability to continue  to recover  the  regulatory  assets we have
deferred,  the investments we plan to make in our electric and gas  transmission
and  distribution  systems.  We will  also be  impacted  by the  effect of lower
assumed  rate of  returns  and lower  fund  balances  on our  pension  and other
postretirement benefit plan (OPEB) expenses.

RESULTS OF OPERATIONS

Operating Revenues

Electric Transmission and Distribution

Electric  Transmission and Distribution revenues decreased $35 million or 4% for
the quarter  ended June 30, 2002 as compared to the quarter  ended June 30, 2001
primarily due to the implementation of a 2% electric rate reduction in August of
2001,  lower DSM revenues,  lower  distribution  sales volumes and a decrease in
miscellaneous  revenues offset by increased commodity sales volumes. The 2% rate
reduction reduced revenues by approximately $18 million and is passed through to
Power  through a  reduction  in the MTC.  As a  result,  electric  energy  costs
decreased by a corresponding  amount.  Revenues also decreased by  approximately
$19 million due to lower  recovery of lost sales  associated  with DSM  programs
through the SBC. Also, lower distribution  sales volumes,  primarily relating to
our industrial customers, reduced revenues by approximately $6 million. Finally,
there was an approximate $12 million decrease in miscellaneous electric revenues
primarily  relating to replacement  capacity charges  (approximately $8 million)
and  fiber  optics  (approximately  $2  million).   Partially  offsetting  these
decreases were higher Basic Generation Service (BGS) or commodity sales volumes,
which increased  revenues by approximately  $22 million and was primarily due to
customers  returning to us from third party suppliers (TPS) as wholesale  market
prices  exceeded the fixed BGS rates. At June 30, 2002, TPS were serving 0.3% of
the customer  load  traditionally  served by us as compared to the June 30, 2001
level of 1.5%.

Electric  Transmission and Distribution revenues decreased $61 million or 3% for
the six months  ended June 30, 2002 as compared to the six months ended June 30,
2001  primarily due to the  implementation  of a 2% electric  rate  reduction in
February of 2001 and another 2% electric rate reduction in August of 2001, lower
DSM revenues,  lower  distribution sales volumes and a decrease in miscellaneous
revenues  offset  by  increased  commodity  sales  volumes.  The  electric  rate
reductions  and the lower DSM revenues  caused a decrease of  approximately  $44
million  and  $19  million,  respectively.  Lower  distribution  sales  volumes,
primarily   relating  to  our   industrial   customers,   reduced   revenues  by
approximately  $25 million.  There was an  approximate  $14 million  decrease in
miscellaneous  electric  revenues  primarily  relating to  replacement  capacity
charges  (approximately $9 million) and fiber optics (approximately $2 million).
Partially offsetting these decreases were higher commodity sales volumes,  which
increased  revenues  by  approximately  $47 million  and were  primarily  due to
customers returning to us from TPS as wholesale market prices exceeded the fixed
BGS rates.

Gas Distribution

Gas distribution revenue decreased $46 million or 13% for the quarter ended June
30,  2002 as  compared  to the  quarter  ended June 30,  2001  primarily  due to
decreased  commodity rates  (approximately  $55 million) offset by increased gas
base rates  (approximately $10 million).  These rates were adjusted based on our
gas rate case settlement, which became effective January 9, 2002.

Gas distribution  revenue decreased $313 million or 22% for the six months ended
June 30, 2002 as compared to the six months ended June 30, 2001 primarily due to
the warmer winter in 2002  (approximately  $80 million) and decreased  commodity
rates   (approximately   $270  million)  offset  by  increased  gas  base  rates
(approximately $36 million).

Operating Expenses

Electric Energy Costs

Electric Energy costs increased $11 million or 2% for the quarter ended June 30,
2002 as  compared to the quarter  ended June 30,  2001  primarily  due to higher
commodity  sales volumes under the BGS contract  with Power  (approximately  $22
million) and an increase in the amortization of the excess electric distribution
depreciation reserve  (approximately $6 million) discussed below in Depreciation
and  Amortization,  partially  offset by lower MTC charges from Power. The lower
MTC charges from Power were  principally  due to the rate  reductions  discussed
above in Electric Transmission and Distribution Revenues,  which reduced our MTC
costs by approximately $18 million.  Overall, changes in the MTC do not have any
impact on our earnings.

Electric  Energy costs  decreased  $10 million for the six months ended June 30,
2002 as compared  to the six months  ended June 30,  2001  primarily  due to the
implementation  of a 2% electric rate  reduction in February of 2001 and another
2% electric rate  reduction in August of 2001 and the effects of weather  offset
by higher  amounts  paid to Power  relating  to the  amortization  of the excess
electric distribution depreciation reserve and higher commodity sales volumes.

Gas Costs

Gas Costs  decreased  $54 million or 22% for the quarter  ended June 30, 2002 as
compared to the quarter  ended June 30, 2001  primarily  due to lower  commodity
rates (approximately $55 million) which became effective January 9, 2002.

Gas costs  decreased  $314 million or 30% for the six months ended June 30, 2002
as compared to the six months ended June 30, 2001  primarily due to lower demand
as a result of the  warmer  weather  in 2002  (approximately  $40  million)  and
decreased commodity rates (approximately $270 million).

Depreciation and Amortization

Depreciation and Amortization  increased $9 million or 10% for the quarter ended
June 30, 2002 as compared to the quarter ended June 30, 2001 primarily due to an
increase in depreciable fixed assets and higher depreciation expense recorded in
accordance  with our increased gas base rates.  Amortization  of the  regulatory
asset recorded for our stranded  costs  increased by  approximately  $3 million.
Miscellaneous   amortization,   primarily  relating  to  regulatory  assets  and
liabilities,  increased  by  approximately  $3 million.  This was offset by a $6
million  reduction  relating  to  higher  amortization  of the  excess  electric
distribution depreciation reserve which is equal to a component of the amount we
pay to Power (but we do not collect this component of the rate from  customers).
Accordingly,  this had no impact on our  earnings,  but reduced our gross margin
and operating cash flows.  For additional  information,  see Note 3.  Regulatory
Assets and Liabilities.

Depreciation  and  Amortization  increased $35 million or 21% for the six months
ended June 30, 2002 as compared to the six months ended June 30, 2001  primarily
due to an increase in  depreciable  fixed assets,  higher  depreciation  expense
recorded in accordance  with our increased gas base rates and an increase of $27
million  relating  to  a  full  period's  recognition  of  amortization  of  the
regulatory asset recorded for our stranded costs,  whose  amortization  began in
February 2001. In addition,  miscellaneous  amortization,  primarily relating to
regulatory assets and liabilities,  increased by approximately $5 million.  This
was offset by an $11 million  decrease  relating to higher  amortization  of the
excess electric distribution depreciation reserve.

Other Income

Other Income decreased $18 million or 75% for the quarter ended June 30, 2002 as
compared  to the  quarter  ended June 30,  2001  primarily  due to a decrease in
interest  income of $16 million and a $2 million  decrease in gains  relating to
the  disposal of assets.  Interest  income  decreased  by $6 million due to PSEG
paying off an intercompany note on April 16, 2001.  Interest income decreased by
approximately  $8 million due to lower amounts of funds being  invested in money
markets in the second quarter of 2002 as compared to the prior period.

Other Income decreased $83 million or 88% for the six months ended June 30, 2002
as  compared  to the six months  ended June 30,  2001  primarily  due to reduced
interest  income of $81 million and a $2 million  decrease in gains  relating to
the disposal of assets. Interest income decreased by $66 million due to interest
income  being  recorded in the prior year for  intercompany  notes from PSEG and
Power.  Interest  income  decreased  by  approximately  $13 million due to lower
amounts of funds  being  invested  in money  markets in 2002 as  compared to the
prior period.

Interest Expense

Interest  Expense  decreased  $10  million and $25 million or 9% and 11% for the
quarter  and six months  ended June 30,  2002 as compared to the quarter and six
months  ended June 30,  2001  respectively  primarily  due to reduced  levels of
short-term and long-term debt.
<PAGE>
Preferred Securities Dividend Requirements of Subsidiaries

Preferred Securities Dividend Requirements of Subsidiaries  decreased $3 million
or 43% for the quarter ended June 30, 2002 as compared to the quarter ended June
30,  2001 and $11  million  or 61% for the six  months  ended  June 30,  2002 as
compared to the six months ended June 30, 2001  primarily due to  redemptions in
March 2001 and June 2001.

Income Taxes

Income taxes  decreased  $19 million or 106% for the quarter ended June 30, 2002
as compared  to the  quarter  ended June 30, 2001 and $54 million or 57% for the
six months ended June 30, 2002 as compared to the six months ended June 30, 2001
almost  entirely due to lower pre-tax income in the current year.  Lower pre-tax
book  income  reduced  income tax expense by  approximately  $18 million and $50
million for the quarter and six months ended June 30, 2002, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We have the following  credit  facilities  for various  funding  purposes and to
provide  liquidity  for  our  $400  million  commercial  paper  program.   These
agreements are with a group of banks and provide for borrowings  with maturities
of up to one year. As of June 30, 2002, we had no commercial paper outstanding.

The following table summarizes our various facilities as of June 30, 2002:

                             Expiration            Total              Primary
                                Date              Facility            Purpose
------------------------  -----------------   -----------------    -------------
                                            (Millions of Dollars)
364-day Credit Facility       June 2003             $200             CP Support
3-year Credit Facility        June 2005              200             CP Support
Uncommitted Bilateral
   Credit Agreement             N/A                   *                Funding

* Availability varies based on market conditions.

Under our Mortgage,  we may issue new First and Refunding Mortgage Bonds against
previous  additions  and  improvements,  provided  that our ratio of earnings to
fixed charges calculated in accordance with our Mortgage is at least 2:1, and/or
against retired  Mortgage  Bonds. At June 30, 2002, our Mortgage  coverage ratio
was 3:1. As of June 30, 2002, the Mortgage would permit up to  approximately  $1
billion  aggregate  principal  amount of new Mortgage Bonds to be issued against
previous additions and improvements. We will need to obtain BPU authorization to
issue any financing  necessary for our capital program,  including  refunding of
maturing debt and opportunistic refinancing.  We have authorization from the BPU
to  issue $1  billion  of  long-term  debt  through  December  31,  2003 for the
refunding of maturing debt and opportunistic refinancing of debt.

On December 27, 2001,  we filed a shelf  registration  statement on Form S-3 for
the issuance of $1 billion of debt and tax deferred preferred securities,  which
was declared effective by the SEC in February 2002.

Since 1986,  we have made regular cash payments to PSEG in the form of dividends
on  outstanding  shares of our common stock.  We paid common stock  dividends of
$150 million and $112 million to PSEG for the six months ended June 30, 2002 and
2001, respectively.
<PAGE>
In prior years, we have issued Deferrable  Interest  Subordinated  Debentures in
connection with the issuance of tax-deductible preferred securities. If payments
on those Deferrable Interest Subordinated Debentures are deferred, in accordance
with their terms,  we may not pay any dividends on our common or preferred stock
until such deferral is cured. Currently, there has been no deferral or default.

CAPITAL REQUIREMENTS

We have substantial commitments as part of our ongoing construction programs. We
expect that the  majority of our capital  requirements  over the next five years
will come from internally  generated  funds,  with the balance to be provided by
the issuance of debt and equity contributions from PSEG.

For the six months ended June 30, 2002 and 2001, we made net plant  additions of
$196  million  and $172  million,  excluding  Allowance  for Funds  Used  During
Construction   (AFDC),   related  to  improvements  in  our   transmission   and
distribution  system, gas system and common facilities.  Our plant additions for
the six months ended June 30, 2002 were included in our current year's forecast.
Our projected construction expenditures for the next five years are as follows:

                                ($ Millions)
       -----------------------------------------------------------------
          2002           2003         2004          2005         2006
       -----------     --------     ---------     --------     ---------
         $ 485         $ 440         $ 440        $ 450         $ 465
       ===========     ========     =========     ========     =========

Our  construction   expenditures  are  primarily  to  maintain  the  safety  and
reliability of our electric and gas transmission  and  distribution  facilities.
Our ongoing  construction  programs are  continuously  reviewed and periodically
revised as a result of changes in economic  conditions,  revised load forecasts,
business   strategies,   site  changes,   cost  escalations  under  construction
contracts,  requirements  of regulatory  authorities and laws, the timing of and
amount of electric and gas transmission and/or distribution rate changes and our
ability to raise necessary capital.

ACCOUNTING ISSUES

Critical Accounting Policies and Other Accounting Matters

Our most critical  accounting  policies include the application of: Statement of
Financial  Accounting  Standards  (SFAS) No. 71,  "Accounting for the Effects of
Certain  Types of  Regulation"  (SFAS 71), for our  regulated  transmission  and
distribution  business and SFAS No. 133, "Accounting for Derivative  Instruments
and  Hedging  Activities",  as amended  (SFAS  133),  to account for our various
hedging transactions.

Accounting for the Effects of Regulation

We prepare our financial  statements in accordance  with the  provisions of SFAS
No. 71, which  differs in certain  respects  from the  application  of Generally
Accepted Accounting Principles (GAAP) by non-regulated  businesses.  In general,
SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect
the economic effects of regulation.  As a result, a regulated entity is required
to defer the  recognition  of costs (a regulatory  asset) or the  recognition of
obligations  (a  regulatory  liability)  if it is  probable  that,  through  the
rate-making  process,  there will be a  corresponding  increase  or  decrease in
future  rates.  Accordingly,  we have  deferred  certain  costs,  which  will be
amortized over various  future  periods.  To the extent that  collection of such
costs or payment of liabilities is no longer  probable as a result of changes in
regulation and/or our competitive  position,  the associated regulatory asset or
liability is charged or credited to income.

As a result of New Jersey deregulation  legislation and regulatory orders issued
by the BPU,  certain  regulatory  assets and liabilities  were recorded.  Two of
these items will have a significant effect on our annual earnings.  They include
the estimated amount of MTC revenues to be collected in excess of the authorized
amount  of  $540  million  and  the  amount  of  excess  electric   distribution
depreciation reserves.

The MTC  was  authorized  by the BPU as an  opportunity  to  recover  up to $540
million (net of tax) of our unsecuritized generation-related stranded costs on a
net present value basis.  The amounts we recover from customers  through the MTC
are paid to  Power,  this  does not  impact  our  earnings.  As a result  of the
appellate reviews of the Final Order, our securitization transaction was delayed
until the first quarter of 2001,  causing a delay in the  implementation  of the
Securitization  Transition Charge (STC),  which would have reduced the MTC. As a
result,  the MTC was being  recovered at a faster rate than  intended  under the
Final Order and a significant  overrecovery  was probable.  In order to properly
recognize  the  recovery of the allowed  unsecuritized  stranded  costs over the
transition period, we recorded a regulatory liability and a charge to net income
of $76 million, pre-tax, or $45 million, after tax, in the third quarter of 2000
for the  cumulative  amount of  estimated  collections  in excess of the allowed
unsecuritized  stranded  costs for the  period  prior to the  generation-related
asset  transfer to Power.  We then began  deferring a portion of these  revenues
each month to  recognize  the  estimated  collections  in excess of the  allowed
unsecuritized stranded costs. As of June 30, 2002, this deferred amount was $185
million,  of which $16 million  relates to the current  year,  and is aggregated
with the SBC.

The  amortization of the Excess Electric  Distribution  Depreciation  Reserve is
another significant  regulatory liability affecting our earnings. As required by
the BPU,  we reduced our  depreciation  reserve  for our  electric  distribution
assets by $569 million and recorded such amount as a regulatory  liability to be
amortized  over the period from January 1, 2000 to July 31,  2003.  Through June
30,  2002,  $324  million has been  amortized  and  recorded  as a reduction  of
depreciation  expense  pursuant to the Final Order, of which $74 million relates
to 2002. The remaining $245 million will be amortized through July 31, 2003.

See Note 3. Regulatory  Assets and  Liabilities for further  discussion of these
and other regulatory issues.

SFAS 133 - Accounting for Derivative Instruments and Hedging Activities

SFAS  133  established   accounting  and  reporting   standards  for  derivative
instruments,   including  certain  derivative   instruments  embedded  in  other
contracts,  and for hedging  activities.  It requires an entity to recognize the
fair  value of  derivative  instruments  held as  assets or  liabilities  on the
balance sheet. In accordance with SFAS 133, the effective  portion of the change
in the fair value of a derivative  instrument designated as a cash flow hedge is
reported in other  comprehensive  income  (OCI),  net of tax, or as a Regulatory
Asset or Liability.  Amounts in  accumulated  OCI are  ultimately  recognized in
earnings when the related hedged forecasted  transaction  occurs.  The change in
the  fair  value  of  the  ineffective  portion  of  the  derivative  instrument
designated as a cash flow hedge is recorded in earnings.  Derivative instruments
that have not been  designated  as hedges are  adjusted  to fair  value  through
earnings.  The  fair  value  of the  derivative  instruments  is  determined  by
reference to quoted market prices,  listed  contracts,  published  quotations or
quotations from counterparties.

For additional information regarding Derivative Financial Instruments,  See Note
5 - Financial Instruments and Risk Management.

Other Accounting Issues

For additional  information on our accounting policies and the implementation of
recently issued  accounting  standards,  see Note 1.  Organization  and Basis of
Presentation and Note 2. Accounting Matters, respectively.


FORWARD LOOKING STATEMENTS

Except for the historical  information contained herein,  certain of the matters
discussed  in this report  constitute  "forward-looking  statements"  within the
meaning  of  the  Private  Securities   Litigation  Reform  Act  of  1995.  Such
forward-looking  statements are subject to risks and uncertainties,  which could
cause  actual  results  to  differ  materially  from  those  anticipated.   Such
statements are based on management's  beliefs as well as assumptions made by and
information  currently  available to  management.  When used  herein,  the words
"will",  "anticipate",   "intend",  "estimate",   "believe",  "expect",  "plan",
"hypothetical", "potential", "projected", "forecast" or variations of such words
and similar expressions are intended to identify forward-looking  statements. We
undertake  no  obligation  to  publicly  update  or revise  any  forward-looking
statements, whether as a result of new information,  future events or otherwise.
The following  review of factors should not be construed as exhaustive or as any
admission  regarding the adequacy of our disclosures prior to the effective date
of the Private Securities Litigation Reform Act of 1995.

In addition to any  assumptions  and other factors  referred to  specifically in
connection with such forward-looking statements, factors that could cause actual
results to differ  materially  from those  contemplated  in any  forward-looking
statements include, among others, the following:

o    failure  to obtain  adequate  and  timely  rate  relief may have an adverse
     impact;
o    deregulation  and the  unbundling  of energy  supplies and services and the
     establishment of a competitive energy marketplace;
o    inability  to  raise  capital  on  favorable  terms to  refinance  existing
     indebtedness or to fund capital commitments;
o    changes in the economic and electricity and gas consumption growth rates;
o    environmental regulation may limit our operations;
o    insurance coverage may not be sufficient; and
o    recession, acts of war or terrorism could have an adverse impact.

Consequently,  all of the  forward-looking  statements  made in this  report are
qualified  by these  cautionary  statements  and we cannot  assure  you that the
results or developments anticipated by us will be realized, or even if realized,
will  have  the  expected  consequences  to or  effects  on us or  our  business
prospects,  financial  condition or results of operations.  You should not place
undue  reliance on these  forward-looking  statements  in making any  investment
decision.  We  expressly  disclaim  any  obligation  or  undertaking  to release
publicly any updates or revisions to these forward-looking statements to reflect
events or circumstances that occur or arise or are anticipated to occur or arise
after  the  date  hereof.  In  making  any  investment  decision  regarding  our
securities,  we are not  making,  and you should not infer,  any  representation
about  the  likely   existence  of  any  particular   future  set  of  facts  or
circumstances.  The  forward-looking  statements  contained  in this  report are
intended  to  qualify  for the safe  harbor  provisions  of  Section  27A of the
Securities Act of 1933, as amended,  and Section 21E of the Securities  Exchange
Act of 1934, as amended.

                      ITEM 3. QUALITATIVE AND QUANTITATIVE
                          DISCLOSURES ABOUT MARKET RISK

The market risk inherent in our market risk sensitive  instruments and positions
is the  potential  loss  arising from  adverse  changes in commodity  prices and
interest rates as discussed in the Notes to Consolidated  Financial  Statements.
Our policy is to use  derivatives  to manage risk  consistent  with our business
plans and prudent practices.  PSEG has a Risk Management  Committee comprised of
executive officers,  which we utilize for an independent risk oversight function
to ensure  compliance  with  corporate  policies  and  prudent  risk  management
practices.  See  Note  5.  Financial  Instruments  and  Risk  Management  for  a
discussion of risks associated with commodity contracts and interest rates.

Credit Risk

We are exposed to credit losses in the event of  non-performance  or non-payment
by counterparties.  We also have a credit management  process,  which is used to
assess,  monitor  and  mitigate  our  counterparty  exposure.  In the  event  of
non-performance or non-payment by a major counterparty,  there may be a material
adverse  impact on our  financial  condition,  results of operations or net cash
flows.

                           PART II. OTHER INFORMATION
                           --------------------------

                            ITEM 1. LEGAL PROCEEDINGS

Certain  information  reported under Item 3 of Part I of Public Service Electric
and Gas  Company's  (PSE&G)  2001 Annual  Report on Form 10-K and the  quarterly
report on Form 10-Q for the quarter ended March 31, 2002 is updated below.

In addition see the following at the pages hereof indicated:

(1)  Form 10-K, Pages 7 and 8. See Pages 7, 11 and 12 regarding our Gas Contract
     Transfer, Docket Nos. GR01050328 and GR01050297.

(2)  Form  10-K,  Pages 10 and 49.  See  Page 6  regarding  our MGP  remediation
     program.

(3)  Form 10-K, Page 49. See Page 6. Investigation and additional  investigation
     by the EPA regarding the Passaic River site. Docket No. EX93060255.

(4)  March 31, 2002 Form 10-Q, Page 18. Con Edison complaint filed against us at
     FERC  pursuant  to  Section  206 of  the  Federal  Power  Act.  Docket  No.
     EL02-23-000. See page 20.

(5)  New Matter: Atlantic City Electric Co., et al. v. Federal Energy Regulatory
     Commission. See page 20.

(6)  New Matter: The filing of our electric rate case. See page 12.

                            ITEM 5. OTHER INFORMATION

Affiliate Standards

Form 10-K, page 6. On February 8, 2002 and March 27, 2002, the BPU issued orders
adopting the Competitive  Service Audit reports on the state's  electric and gas
utilities.  The audit report generally concluded that we were in compliance with
the BPU's Affiliate Standards,  and the BPU ordered  implementation of 24 of the
auditor's recommendations, to which we did not specifically object.

On July 1, 2002, we filed our Affiliate Standards  compliance plan in accordance
with the  BPU's  regulations.  Also in July  2002,  the BPU  commenced  its next
regular audit of the state's electric and gas utilities' competitive activities.
The audit is expected to continue through the Spring of 2003.

Uranium Enrichment Decontamination and Decommissioning Fund

Form 10-K,  page 11. In accordance  with the EPAct,  domestic  entities that own
nuclear  generating  stations  are  required to pay into a  decontamination  and
decommissioning   fund,  based  on  their  past  purchases  of  U.S.  government
enrichment services.  Along with other nuclear generator owners, PSEG filed suit
in the U.S. Court of Claims and in the U.S. District Court, Southern District of
New York to recover these costs.  In July 2002,  PSEG withdrew from this lawsuit
without  prejudice,  due to an  unfavorable  decision  against  another  nuclear
generator owner in the lawsuit.

FERC Notice of Proposed Rule Making (NOPR)

Form 10-K,  page 8. On July 31, 2002 the FERC issued a NOPR to create a Standard
Market Design for the wholesale  electricity  markets in the United States.  The
NOPR seeks to improve the  consistency  of market rules  throughout the country,
including  issues related to reliability,  market power concerns,  transmission,
pricing, congestion,  governance and other issues. We cannot predict the outcome
of this  matter or its impact  upon us if  adopted,  which  could  significantly
affect transmission and generation in the various markets in which we operate.

Con Edison Complaint

March 31, 2002 Form 10-Q,  Page 18. On November 15, 2001,  Consolidated  Edison,
Inc. (Con Edison) filed a complaint  against us at the Federal Energy Regulatory
Commission (FERC or Commission) pursuant to Section 206 of the Federal Power Act
asserting that we had breached  agreements  covering 1,000 MW of transmission by
curtailing service and failing to maintain sufficient system capacity to satisfy
all of our  service  obligations.  We denied  the  allegations  set forth in the
complaint.  While finding that Con Edison's  presentation  of evidence failed to
demonstrate several of the allegations, on April 26, 2002, FERC found sufficient
reason to set the  complaint  for  hearing.  An  initial  decision  issued by an
administrative  law judge on April 25, 2002 upheld our claim that the  contracts
do not require the  provision of "firm"  transmission  service to Con Edison but
also accepted Con Edison's contentions that we were obligated to provide service
to Con Edison  utilizing all the facilities  comprising  our  electrical  system
including  generation  facilities and that we were  financially  responsible for
above-market  generation  costs needed to  effectuate  the desired  power flows.
Under FERC  procedures,  an initial decision is not binding unless and until its
findings have been approved by the Commission. We filed a brief taking exception
to the adverse  findings  of the April 25,  2002 order and believe  that we have
presented meritorious arguments supporting our interpretation of the contractual
obligations. A Commission decision concerning the findings of the April 25, 2002
order  was  expected  on July  31,  2002.  Settlement  discussions  between  the
companies  with respect to this matter have been on-going and, on July 17, 2002,
representatives  of the companies met for settlement  discussions  mediated by a
FERC administrative law judge. Based on progress made at these discussions,  Con
Edison  sought  to  extend  the  date  for the  issuance  of the  FERC  decision
addressing  the April 25, 2002  initial  decision and to extend the date for the
commencement  of a hearing with  respect to issues in the case not  addressed by
the April 25, 2002 initial decision. At present, in the event the dispute is not
settled,  the FERC  decision is expected on  September  11, 2002 and the hearing
before the administrative law judge will commence in October 2002. If Con Edison
is successful in litigation, we could be required to provide future transmission
services with uneconomic  generation  resources at a substantial cost to us. The
findings in the April 25, 2002 initial decision  notwithstanding,  we believe we
have complied with the terms of the  Agreements and will  vigorously  defend our
position. The nature and cost of any remedy, which is expected to be prospective
only, cannot be predicted. Further, even in the event settlement is reached with
Con Edison, we could still be required to bear substantial  levels of additional
costs. Docket No. EL02-23-000.

FERC Order and PJM Restructuring

New Matter:  Atlantic  City Electric  Co., et al. v. Federal  Energy  Regulatory
Commission.  On July 12, 2002, the United States Court of Appeals, D.C. Circuit,
issued an opinion in favor of us and the other utility petitioners, reversing an
order of the  FERC  relating  to the  restructuring  of PJM into an  Independent
System  Operator  (ISO).  The Court agreed with our position and ruled that: (1)
FERC lacks  authority to require the utility  owners to give up their  statutory
rights  under  Section 205 of the Federal  Power Act.  Hence,  FERC was wrong to
require a modification to the PJM ISO Agreement eliminating their rights to file
changes  to rate  design;  (2) FERC lacks  authority  under  Section  203 of the
Federal  Power Act to require  the  utility  owners to obtain  approval of their
withdrawal  from the PJM ISO.  Hence,  FERC had no right  under  Section  203 to
eliminate the withdrawal rights to which the utilities had agreed; and (3) As to
our situation,  FERC could not accomplish a generic existing  precedent,  it was
first  necessary  to make a  particularized  finding  with respect to the public
interest,  which was not done here.  This decision could be subject to an appeal
to the United States Supreme Court by the respondents, including the FERC.
<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
     --------------                --------
     10                            Basic Generation Service (BGS) Contract

     12                            Computation of Ratios of Earnings to Fixed
                                   Charges

     12(A)                         Computation of Ratios of Earnings to Fixed
                                   Charges Plus Preferred Securities

     99                            Certification by E. James Ferland, Chairman
                                   of the Board and Chief Executive Officer of
                                   Public Service Electric and Gas Company
                                   Pursuant to Section 1350 of Chapter 63 of
                                   Title 18 of the United States Code

     99.1                          Certification by Robert E. Busch, Senior Vice
                                   President - Finance and Chief Financial
                                   Officer of Public Service Electric and Gas
                                   Company Pursuant to Section 1350 of Chapter
                                   63 of Title 18 of the United States Code


(B)  Reports on Form 8-K and 8-K/A:

     Date of Report                Form                    Items Reported
     --------------                ----                    --------------
     July 17, 2002                 8-K                     Items 5 and 7
     July 29, 2002                 8-K/A                   Items 5 and 7

<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:        PATRICIA A. RADO
                     ---------------------------------------
                                Patricia A. Rado
                          Vice President and Controller
                         (Principal Accounting Officer)


Date: August 2, 2002