SECURITIES AND EXCHANGE COMMISSION

                     Washington, D.C.  20549




                            FORM 8-K

                         CURRENT REPORT




             Pursuant to Section 13 or 15(d) of the
                 Securities Exchange Act of 1934


                Date of Report:  June 7, 1994




                PACIFIC GAS AND ELECTRIC COMPANY
     (Exact name of registrant as specified in its charter)



California                    1-2348              94-0742640     

(State or other juris-      (Commission         (IRS Employer
diction of incorporation)   File Number)   Identification Number)

77 Beale Street, P.O.Box 770000, San Francisco, California 94177
       (Address of principal executive offices) (Zip Code)








Registrant's telephone number, including area code:(415) 973-7000






Item 5.  Other Events

A.   California Public Utilities Commission (CPUC) Proceedings -
     Electric Industry Restructuring

As previously disclosed, in April 1994, the CPUC issued an order
instituting a rulemaking and investigation (OIR/OII) on electric
industry restructuring.  The proposal, which is subject to
comment and modification, involves two major changes in electric
industry regulation.  The first would move electric utilities
from traditional cost-of-service to performance-based ratemaking. 
The second would unbundle electric services and require the
phase-in of retail wheeling or direct access to electric
generation over the six-year period from 1996 to 2002.

The CPUC has scheduled four full panel hearings in June, July and
August 1994 to hear public comments on its proposal.  The CPUC
has indicated that it anticipates adopting a final policy
statement no earlier than October 1994.  Implementation hearings
will continue into 1995.

On June 7, 1994, the Company filed its initial comments on the
CPUC's proposal on retail wheeling of electricity.  In its
comments, the Company indicated that it shares the CPUC's goal of
effecting the transition to a more competitive world in a manner
which:  (1) achieves competitive electric prices for consumers;
(2) maintains utilities' financial integrity; (3) sustains an
electric supply system which provides reliable service for all
Californians; (4) avoids shifting of costs from one group of
customers to another (in particular, to residential customers);
and (5) allows continuation of California's environmental and
social benefit programs.  The Company noted that to achieve these
objectives, the CPUC must resolve fundamental legal,
jurisdictional and public policy issues and obtain the approval
of the Federal Energy Regulatory Commission (FERC) and the
California State Legislature.

The Company's proposal includes the following key elements:

(1)  Implementation Schedule:  The Company proposes an
implementation schedule that would allow all electric power
consumers access to a retail electric power marketplace by
January 1, 2008.  Direct access would commence as proposed by the
CPUC on January 1, 1996, for large customers receiving service at
transmission voltage levels.  Each year, additional groups of
customers would be included in the direct access category.

Industrial and large commercial customers which would be eligible
in the period 1996 through 2002 represent approximately 30
percent of electric generation revenues.  The remaining non-
residential customers which would be eligible in the period 2003
through 2006 represent approximately 34 percent of electric
generation revenues.  Residential customers would be eligible in
2007 and 2008 and represent approximately 36 percent of electric
generation revenues.  The Company indicated that its proposed
schedule, coupled with pricing flexibility, will substantially
reduce transition costs to consumers.

(2)  Transition Costs:  There are three main categories of
potential transition costs identified by the Company - (i)
ongoing costs associated with utility-owned generation
facilities; (ii) ongoing costs associated with above market
payments under "qualifying facilities" power purchase agreements;
and (iii) costs and obligations incurred in the past under
traditional cost-of-service regulation.  The Company's proposal
deals with these costs in two ways: by allowing sufficient time
to reduce the amount of transition costs and by imposing
transition charges which must be paid by all customers.

     (i)  With respect to utility-owned generation facilities, if
     the Company's proposals are adopted in their entirety, the
     Company would accept the full market risk of recovery of the
     ongoing costs of its generation facilities, including Diablo
     Canyon under the pricing formula in the 1988 settlement
     agreement, whether due to discounted prices or lost sales.

     (ii)  The Company purchases approximately 20 percent of its
     generation from "qualifying facilities" under long-term
     agreements mandated or approved by the CPUC, some of which
     result in payments above current market levels.   The
     Company indicated that the uneconomic portion of the energy
     and capacity payments provided under these agreements should
     be included in a transition charge borne by all customers
     interconnected to the system.  The Company estimates that in
     1994 it will pay approximately $800 million over market
     rates for these purchases.

     (iii)  The Company proposes transition cost recovery for
     existing regulatory assets and certain other costs and
     obligations arising out of historic utility activities
     related to electric generation, such as the unamortized
     balancing accounts related to the Energy Cost Adjustment
     Clause and the Electric Revenue Adjustment Mechanism, the
     unamortized premium on reacquired debt, utility deferred
     taxes, workers' compensation and disability claims,
     pensions, environmental mitigation costs associated with
     existing and retired electric plants and post-retirement
     benefits other than pensions.

(3)  Pricing Flexibility and Market Risk for Utility Electric
Power Sales:  The Company will continue to provide full retail
service at regulated rates to full service customers.  For direct
access customers, the Company proposes that it be able to compete
to sell them unbundled electric power, in a way that insulates
full-service customers from any lost contribution to margin,
whether due to reduced prices or lost sales.


When direct access to generation is available to all customers,
the Company should be free to use its generation resources,
including power purchase arrangements, in the competitive
marketplace as it sees fit.  

(4)  Environmental and Social Programs:  The Company proposes
that none of the existing environmental and social programs
should be discontinued because of a move to direct access. 
Unless and until a policy decision is made to discontinue a
program, costs should be allocated to all electric customers,
including those who elect direct access, and included as a
separately identified component on customers' bills.

(5)  Obligation to Serve:  For the foreseeable future, the
Company proposes to retain an ongoing obligation to provide
electric power for residential customers, but proposes that the
utility should be obligated to provide electric supply only on a
best efforts basis to non-residential direct access customers
which decide to return to the Company for their power supply and
on terms of service to be negotiated.


Financial Impact of the Direct Access portion of the OIR/OII: 
Based on the regulatory framework in which it operates, the
Company currently accounts for the economic effects of regulation
in accordance with the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects
of Certain Types of Regulation."  As a result of applying the
provisions of SFAS No. 71, the Company has accumulated
approximately $3.5 billion of regulatory assets, including
balancing accounts, as of March 1994.  It is currently estimated
that approximately $1.2 billion of regulatory assets is
attributable to electric generation, excluding balancing accounts
which are expected to be recovered over the next several years. 
The amount related to electric generation is based on the
Company's estimate of the allocation of these assets; the actual
amount could vary depending on the allocation methods adopted by
the CPUC.

In the event that recovery of specific costs through rates
becomes unlikely or uncertain for a portion or all of the
Company's utility operations, whether resulting from the
expanding effects of competition or specific regulatory actions
which move the Company away from cost-of-service ratemaking, SFAS
No.71 would no longer apply.  Discontinuation of SFAS No. 71
would cause the write-off of applicable portions of regulatory
assets, which could have a significant adverse impact on the
Company's financial position or results of operations.

Absent a recovery mechanism for the regulatory assets and certain
other costs and obligations attributable to electric generation,
some or all of those regulatory assets would be written-off. 
However, under the Company's proposal, the amount of such write-
off would be significantly reduced.

If the Company's implementation schedule for direct access to
electric generation is adopted, the Company anticipates that it
will shorten the depreciable life for Diablo Canyon from 2016 to
2008, which would increase the average annual depreciation
expense by approximately $130 million and be borne by the
Company's shareholders.

The CPUC's OIR/OII could impact (i) the Company's recovery of its
costs and investments in electric utility assets, (ii) the Diablo
Canyon rate case settlement and (iii) the continued application
of SFAS No. 71.  The final determination of the impact will be
dependent on the form of regulation, including transition
mechanisms, if any, ultimately adopted by the CPUC, and the
effects of competition.  The Company is unable to predict the
ultimate effect of the OIR/OII on its financial position or
results of operations.


B.   Restructuring of Canadian Gas Supply Arrangements -

On May 17, 1994, the FERC issued an order approving Pacific Gas
Transmission Company's (PGT) application to recover in rates $154
million in settlement payments to Canadian gas producers.  The
settlement payments were made pursuant to a Decontracting Plan
implemented by the Company, PGT, the Company's wholly owned gas
pipeline subsidiary, Alberta and Southern Gas Co. Ltd. (A&S), a
wholly owned subsidiary of the Company, and approximately 190
Canadian gas producers, that restructured the Company's Canadian
gas supply arrangements.  

PGT's application was made pursuant to the transition cost
recovery mechanism (TCRM) approved by the FERC in July 1993. 
Under the TCRM, PGT will absorb 25% of approved transition costs,
including settlement payments incurred in connection with the
termination of A&S' contracts with Canadian gas producers, with
the remainder of such costs to be recovered from PGT's shippers.

The CPUC had filed a limited challenge to PGT's application,
challenging the eligibility for recovery under the TCRM of
certain settlement payments and requesting a technical conference
or hearing to determine if other payments made by PGT are
consistent with the TCRM.  In its May 17 order, the FERC denied
the CPUC's challenge and its request for a hearing.

C.  Cities Franchise Fees Litigation

On May 13, 1994, the City of Santa Cruz filed a complaint in
Santa Cruz County Superior Court against the Company on behalf of
itself and purportedly as a class action on behalf of 107 cities
with which the Company has certain electric franchise contracts.
Franchise contracts require the Company to pay fees on an annual
basis to cities and counties for the right to use or occupy
public streets and roads.  The complaint alleges that, since at 
least 1988, the Company has intentionally underpaid its franchise
fees to the cities in an unspecified amount.

The complaint alleges that the Company has asked for and accepted
electric franchises from the cities included in the purported
class, which provide for lower franchise payments than required
by franchises granted by other cities in the Company's service
territory.  Plaintiff asserts that this was done in an unlawfully
discriminatory manner based solely on location.  The plaintiff
also alleges that the transfer of these franchises to the Company
by its predecessor companies was not approved by the CPUC as
required, and, therefore, all such franchise contracts are void.

Based on limited investigation thus far, should the cities
prevail on the issue of franchise fee calculation methodology,
the Company's annual system-wide city electric franchise fees
could increase by approximately $17 million.  The complaint also
seeks damages for alleged underpayments for the years 1987
through 1993, which could be as much as $97 million, plus
interest estimated at approximately $18 million through April 15,
1994.

The Company believes that the ultimate outcome of the franchise
fees litigation will not have a significant adverse impact on its
financial position or results of operations.

D.  Management Changes

On June 2, 1994, the Company announced that Stanley T. Skinner,
currently president and chief operating officer of the Company,
will become president and chief executive officer (CEO),
effective July 1, 1994.  Richard A. Clarke, currently the
chairman of the board and CEO of the Company, will continue to
serve as chairman.  Robert D. Glynn Jr., senior vice president
and general manager of the Company's customer energy services
business unit, has been promoted to executive vice president,
effective July 1, 1994.  Mr. Glynn will assume direct supervision
of the utility business units formerly reporting to Mr. Skinner. 

  
 













                         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.


                              PACIFIC GAS AND ELECTRIC COMPANY


                                   
                                 /s/ THOMAS C. LONG                            
                              By ________________________________

                                 THOMAS C. LONG
                                 Controller                       
   

Dated:  June 7, 1994