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: September 9, 1996




		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.  Electric Industry Restructuring Legislation

On August 31, 1996, the California State Legislature adopted 
legislation, Assembly Bill (AB) 1890, which comprehensively 
restructures the regulation of electric utilities in California.  The 
legislation is supported by Pacific Gas and Electric Company (PG&E) 
and a coalition of customer, utility, business, environmental, 
agricultural, labor, independent power producer, and local government 
groups.  The legislation now goes to the Governor, who will have 
thirty days to sign or veto it.  The legislation would be effective 
upon enactment.  The following are the major provisions of AB 1890:

Recovery of Uneconomic Costs:

The legislation authorizes utilities subject to the regulation of the 
California Public Utilities Commission (CPUC) to recover the 
uneconomic costs of their generation-related assets and obligations 
(referred to in the legislation as "Competition Transition Costs"). 
These uneconomic costs (CTCs) would be recovered from all customers 
(with certain exceptions) through a non-bypassable charge included as 
part of rates over the period ending December 31, 2001, with the 
possibility of extension beyond December 31, 2001 for certain CTCs, 
such as employee-related transition costs (recoverable through 
December 31, 2006) and costs resulting from implementation of direct 
access, creation of a power exchange and independent operation of the 
transmission system.  As a prerequisite to any consumer obtaining 
direct access services (see "Direct Access," below), the consumer must 
agree to pay its applicable non-bypassable CTC charge, through the 
rates or tariffs under which the consumer is obtaining service from 
the utility, or by written confirmation if the consumer is not using 
the utility's facilities for direct access.  Until January 1, 2002, 
electricity marketers must advise their direct access customers of 
their obligation to execute a written confirmation of their obligation 
to pay the applicable non-bypassable CTC charge.

Generation-related assets and obligations are defined to include those 
costs and categories of costs consisting of generation facilities, 
generation-related regulatory assets, nuclear settlements, and power 
purchase contracts, including restructuring, renegotiations or 
terminations thereof approved by the CPUC, that were being collected 
in rates as of December 20, 1995, along with costs incurred after that 
date for capital additions to such generating facilities that the CPUC 
determines are reasonable and necessary to maintain the facilities 
through December 31, 2001. Employee-related transition costs 
associated with officers, senior supervisory employees, and 
professional employees performing predominantly regulatory functions 
are not recoverable.

CTCs associated with existing power purchase contracts, such as those 
for purchases from Qualifying Facilities (QFs) under the Public 
Utility Regulatory Policies Act of 1978, also would be recoverable 
through non-bypassable rates, except that the recovery period would be 
over the duration of the contract or any restructuring thereof.  

CTCs associated with utility-owned fossil generation would be limited 
to the uneconomic net book value of the fossil capital investment as 
of January 1, 1998, plus the costs of capital additions subsequent to 
December 20, 1995 that the CPUC determines are reasonable and 
necessary to maintain the facilities through December 31, 2001.  
Operating costs for such facilities would generally not be recoverable 
except through market-based rates or if the facilities are required to 
be operated for reliability purposes by the Independent System 
Operator (ISO) to be developed in connection with restructuring, as 
discussed below.  PG&E will be permitted to retain any earnings from 
the operation of such plants for reliability purposes, and will not be 
required to apply those earnings to offset recovery of CTCs.

As discussed below, the recovery of CTCs must be consistent with not 
increasing rates above rate levels in effect on June 10, 1996.  The 
CPUC's calculation of uneconomic costs associated with utility-owned 
generation would be based on a mechanism which nets the negative value 
of all above-market utility-owned generation assets against the 
positive value of all below-market utility-owned generation.  The 
legislation provides that the CPUC's determination of the CTCs 
eligible for recovery and of the valuation of the assets under these 
criteria, which must occur by January 1, 2002, may not be rescinded or 
altered by subsequent CPUC action.

The legislation provides for certain customers to be exempt from 
paying CTCs.  These exemptions include certain cogeneration and self-
generation projects, certain irrigation districts, the Bay Area Rapid 
Transit District (BART), and the University of California at Davis.  
Fifty million dollars of the costs attributable to the irrigation 
district exemptions would be recoverable through March 31, 2002, but 
the costs of the other exemptions would be recoverable only if 
recovered by December 31, 2001, without raising rates in effect as of 
June 10, 1996.  The costs of such exemptions (other than the BART 
exemption) may be allocated only to the customer classes of which the 
exemptees are members.

Nuclear decommissioning costs would continue to be recovered through a 
non-bypassable charge separate from CTCs until fully recovered.  
Recovery of nuclear decommissioning costs may be accelerated.

The legislation cites the Restructuring Rate Settlement (Restructuring 
Agreement) between PG&E and a spectrum of agricultural, commercial, 
industrial, union, independent power and consumer groups, as an 
example of a CTC cost recovery plan authorized by the legislation.

Rate Levels:

In order to provide utilities a reasonable opportunity to recover 
their CTCs on an accelerated basis, the legislation, with certain 
exceptions, requires that retail electric rates be set at levels equal 
to those in effect as of June 10, 1996, and remain at those levels 
until the earlier of March 31, 2002 or when CTCs have been fully 
recovered.  The June 10, 1996 rate level is inclusive of CTCs.

The legislation states that it is the Legislature's intent that 
utilities be required and authorized to refinance the costs of CTCs 
for residential and small commercial customers (customers who have 
less than 20 kilowatts of peak demand) so that their rates will be 
reduced no less than 10 percent for 1998 continuing through 2002.  In 
order to achieve this rate reduction, utilities are authorized to 
finance a portion of their CTCs with proceeds from the sale of "rate 
reduction bonds" issued by the California Infrastructure and Economic 
Development Bank (IED Bank).  The rate reduction bonds will have a 
term not to exceed ten years.  Residential and small commercial 
customers will pay the principal and interest on the rate reduction 
bonds through a separately identified component of their electric 
utility bill.  Utilities will act as collection agent, and will remit 
principal and interest payments to the IED Bank or to a special 
purpose trust authorized by the IED Bank to issue bonds.  The 
legislation requires that utilities, by no later than June 1, 1997, 
apply concurrently to the CPUC and the IED Bank, respectively, for 
financing orders and for issuance of rate reduction bonds sufficient 
to accomplish the rate reduction for residential and small commercial 
customers.

The legislation provides that financing orders issued by the CPUC and 
rate proceeds made the basis of issuance of rate reduction bonds may 
not be limited, altered, amended or rescinded by the CPUC or by the 
State of California, except for adjustments to the amounts necessary 
to ensure timely recovery of all transition costs financed by the 
financing orders and rate reduction bonds.

The legislation also states that an anticipated result of 
implementation of the legislation is that rates for residential and 
small commercial customers would be reduced cumulatively by no less 
than 20 percent by April 1, 2002, compared to rates in effect on June 
10, 1996.  The legislation provides that the CPUC will determine 
whether the April 1, 2002 rate reduction has been met by excluding the 
costs of competitively procured electricity and the costs associated 
with the rate reduction bonds issued to finance a portion of CTCs.

Independent System Operator and Power Exchange/System Reliability 
Standards:

The legislation requires the CPUC to facilitate the development of an 
ISO and a Power Exchange (PX), and establishes a five-member Oversight 
Board to (1) ensure that the ISO and PX are incorporated as public 
benefit, non-profit corporations under California law; (2) oversee the 
ISO and PX, (3) appoint members of the governing boards of the ISO and 
PX, and (4) serve as an appeal board for appeals by ISO governing 
board members from majority decisions of the ISO governing board.  

Three members of the Oversight Board are to be California residents 
and electric ratepayers appointed by the Governor from a list jointly 
recommended by the CPUC and the California Energy Commission, and 
subject to confirmation by the California State Senate.  One member is 
to be a member of the California State Assembly appointed by the 
Speaker thereof, and one member is to be a member of the State Senate 
appointed by the Committee on Rules thereof.  The legislative members 
will be non-voting members.  Members of the Oversight Board will be 
appointed for staggered three-year terms.

The ISO and PX Governing Boards are to be composed of California 
residents, and will include, but are not limited to, representatives 
of investor-owned utility transmission owners, publicly-owned utility 
transmission owners, nonutility electricity sellers, public buyers and 
sellers, private buyers and sellers, industrial end-users, commercial 
end-users, residential end-users, agricultural end-users, public 
interest groups, and non-market participant representatives.  A simple 
majority of the ISO Governing Board must be unaffiliated with electric 
generation, transmission or distribution corporations.

It is the intent of the legislation that both California's investor-
owned utilities and its publicly-owned utilities commit control of 
their transmission facilities to the ISO.  Publicly-owned utilities 
are authorized to recover their generation-related transition costs 
through the imposition of exit fees if they have otherwise committed 
their transmission system control to the ISO.  The ISO is required to 
ensure reliable transmission services consistent with planning and 
operating reserve criteria no less stringent than those established by 
the Western Systems Coordinating Council (WSCC) and the North American 
Electric Reliability Council. Consistent with these criteria, the ISO 
must adopt inspection and maintenance standards for investor-owned and 
publicly-owned utilities no later than March 31, 1997.  

Within six months of Federal Energy Regulatory Commission (FERC) 
approval of establishment of the ISO, the ISO must provide a report to 
the Legislature on current reliability criteria in the WSCC, the 
economic cost of system outages and cost-effective options to prevent 
them.  The ISO is required to review the causes of major system 
outages, and is authorized to order appropriate sanctions on 
transmission owners responsible for such outages, subject to FERC 
approving that authority.  The CPUC is required to seek approval from 
the FERC to give the ISO the authority to secure generating and 
transmission resources necessary to meet the reliability criteria.  
Finally, it is the intent of the legislation that California enter 
into an interstate compact with other western states to establish 
enforceable reliability standards for the interconnected regional 
transmission and distribution systems.

The legislation requires that no later than March 31, 1997, the CPUC 
adopt inspection, maintenance, repair and replacement standards for 
the distribution systems of investor-owned utilities.  In order to 
assure reliability, in any sale (but not spin-off) of utility electric 
generating facilities initiated prior to December 31, 2001 and 
approved by the CPUC prior to December 31, 2002, the CPUC must require 
that the selling utility contract with the purchaser for the selling 
utility, an affiliate, or a successor corporation to operate and 
maintain the facility for at least two years.  This requirement would 
not apply if the plant were shut down or otherwise not operated.  The 
CPUC may, but is not required to, impose these requirements on sales 
initiated on or after January 1, 2002.

Direct Access:

The legislation authorizes direct transactions between electricity 
suppliers and end-use customers, beginning no later than January 1, 
1998, and on a phased-in schedule through December 31, 2001, that is 
equitable to all customer classes.  Aggregation of customer electrical 
load for such direct transactions is authorized, provided that 
customers consent to aggregation through a positive written 
declaration.  No change in the aggregator or electric service provider 
of a residential or small commercial customer may be made unless the 
change complies with certain "anti-slamming" provisions.  Customers 
would be eligible for direct transactions regardless of any phase-in 
schedule if at least one-half the customer's electrical load is 
supplied by a certified renewable resource provider.

Base Revenue Increases:

The legislation specifically provides for annual increases in base 
revenues for PG&E, effective in 1997 and 1998, equal to the inflation 
rate (as measured by the consumer price index) for the prior year plus 
two percentage points.  The base revenue increases do not affect the 
overall electric rates for customers, which will be frozen, per the 
legislation.  The increase will remain in effect pending a general 
rate case to be filed by PG&E no later than the end of 1997 for rates 
to be effective in January 1999.  However, these base revenue 
increases will not create any presumption regarding the level of base 
revenues to be used for any future base rate or performance-based 
ratemaking.  Further, the base revenue increases must be used for 
enhancing transmission and distribution system safety and reliability, 
and any such revenues not expended for such purposes shall be credited 
against subsequent safety and reliability revenue requirements in 
future years.

Regulation of Generation Facilities:

The legislation provides that generation facilities owned by a public 
utility prior to January 1, 1997 and subject to rate regulation by the 
CPUC will continue to be regulated by the CPUC only until the 
facilities have undergone market valuation in connection with the CTC 
recovery mechanism.  However, if the public utility wishes to retain 
ownership of the facility in the same corporation as its distribution 
utility after market valuation has taken place, the utility must 
demonstrate to the CPUC that such continued ownership in the same 
corporation is in the public interest and would not confer an undue 
competitive advantage on the utility.

The legislation also provides that owning, controlling, operating or 
managing a power plant used for direct access or for sales to the PX 
would not subject a corporation or person to CPUC regulation solely by 
reason of such ownership, control, operation, management or sale.

Consumer Protection:

Except for utilities already regulated by the CPUC, entities which 
offer electrical services to residential and small commercial 
customers must register with the CPUC, provide specific information to 
customers as part of its services, and be subject to specific claims 
and damages procedures.  This requirement would expire January 1, 2002 
unless renewed by legislation.  Existing utilities must develop 
consumer information training programs to assist customers in 
understanding their supply options under the new market structure.  
All suppliers must follow verification procedures before customers may 
be shifted from their current supplier.

Public Benefit Programs:

The legislation provides that energy efficiency, research and 
development, and low income programs will be funded in electric rates 
pursuant to a separate, non-bypassable charge at current levels from 
January 1, 1998 through December 31, 2001.  The June 10, 1996 rate 
level is inclusive of this public benefit charge.  Under this 
provision, PG&E is obligated to fund energy efficiency and 
conservation programs at $106 million per year; research and 
development programs at $30 million per year; and renewable 
technologies at not less than $48 million per year.  The CTC recovery 
period may be extended three months beyond December 31, 2001 to the 
extent necessary to assure that the aggregate amount of funds 
collected for renewable technologies programs from investor-owned 
utilities is $540 million.  Public interest funds not used for 
transmission and distribution research, and renewable research and 
development funds collected under these rates will be transferred to 
and administered by the California Energy Commission.  Publicly-owned 
utilities must establish a public benefits charge commensurate to the 
lowest expenditure of the investor-owned utilities, on a percent of 
revenue basis.


Short Run Avoided Cost Pricing by QFs

The legislation provides that so-called "short run avoided cost 
payments" paid by investor-owned utilities to nonutility generators, 
including QFs, will be based on a formula which references the average 
of current California natural gas border indices.  When the CPUC 
determines that the PX is functioning properly (see "Independent 
System Operator and Power Exchange/System Reliability Standards," 
above), and either (1) the utility is subject to market-based rates 
for its fossil generation unit, or (2) the utility has divested 90 
percent of its gas fired generation units, the short run avoided cost 
price will be based on the PX price.  However, at any time, nonutility 
generators may exercise a one-time option to base their short run 
avoided cost price on the PX price.

Restructuring of Publicly Owned-Utilities

The legislation restructures the regulation and authority of publicly-
owned utilities in parallel with the provisions applicable to 
investor-owned utilities, as follows:

- --Publicly-owned utilities will determine whether to offer direct 
access on their systems, subject to a phase-in period commencing no 
later than January 1, 2000;

- --If the publicly-owned utility offers direct access, it may establish 
a non-bypassable CTC charge;

- --After the ISO is approved, neither a publicly-owned utility nor an 
investor-owned utility may recover CTCs under the legislation unless 
it has committed control of its transmission facilities to the ISO; 
and

- --The legislation reflects an agreement between local publicly-owned 
electric utilities and investor-owned utilities on pricing principles 
for transmission facilities committed to the ISO.  Initially, utility 
specific access charges and rates will honor all of the terms and 
conditions of existing transmission services contracts and will 
recognize any wheeling revenues of existing transmission service 
arrangements to the particular transmission owner.  No later than two 
years after the initial operation of the ISO, the ISO will recommend a 
revised rate structure.  If the ISO transmission rates are different 
than those in effect for any transmission facility owner, the amount 
of any difference may be tracked and recovered in rates over an 
amortization period which would commence after termination of the 
period for recovery of CTC costs.

B.  CPUC Reform Legislation

In conjunction with its adoption of comprehensive legislation 
restructuring the electric utility industry, the California 
Legislature also enacted legislation which, if signed by the Governor, 
would implement certain reforms to the structure and procedures of the 
CPUC and for judicial review of certain CPUC proceedings.  Among other 
things, the legislation (SB960 and SB1322) modifies the process for 
selecting the head of the Division of Ratepayer Advocates (DRA), by 
making that position one filled by and serving at the pleasure of the 
Governor, subject to confirmation by the California Senate.  Currently 
the director of the DRA, which under the legislation would remain a 
division of the CPUC whose mission is to represent the interests of 
public utility customers in CPUC proceedings, is appointed by the 
CPUC.  The legislation would also institute new procedures for 
classifying and processing various type of CPUC proceedings.  The 
legislation requires the CPUC to classify proceedings either as 
adjudicatory, ratesetting or quasi-legislative, and to employ 
different ex parte rules and hearing procedures depending on the 
classification.  Generally, ex parte contacts with decision makers are 
prohibited in adjudicatory proceedings (defined as complaint cases and 
enforcement-type proceedings), are limited in ratesetting proceedings 
in a manner to provide all parties with an equal opportunity to engage 
in such contacts, and are unlimited in quasi-legislative proceedings.  
The legislation also modifies the mechanism for judicial review of 
adjudicatory proceedings.  Currently all appeals of CPUC decisions are 
by discretionary writ directly to the California Supreme Court.  Under 
the legislation, appeals of adjudicatory proceedings may also be 
requested of the California Court of Appeals.

C.  California Public Utilities Commission Proceedings

	1.  Electric Industry Restructuring

		a.  Diablo Canyon/Rate Freeze Application

In March 1996, PG&E filed an application with the CPUC seeking 
approval to modify the Diablo Canyon Rate Case Settlement (Diablo 
Settlement) contingent upon the adoption of a five-year customer 
electric rate freeze, effective January 1, 1997 (Diablo Canyon/Rate 
Freeze Application).  On August 29, 1996, the CPUC's DRA issued its 
report and recommendations on PG&E's Diablo Canyon/Rate Freeze 
Application.

In its report, the DRA indicates that it supports PG&E's endeavor to 
eliminate its above-market generation costs by the year 2001, but DRA 
recommends several modifications to PG&E's proposal.  Among other 
things, the DRA recommends changes to the performance-based 
Incremental Cost Incentive Price (ICIP) mechanism to reduce the pre-
set price per kilowatt-hour (kWh) paid for plant output, which 
escalates over the period 1997 - 2001.  Revenues under the ICIP are 
intended to recover Diablo Canyon Nuclear Power Plant's (Diablo 
Canyon) variable costs and incremental capital additions.  The ICIP 
prices proposed by PG&E and recommended by the DRA are set forth in 
the following table.


			Proposed ICIP Prices

(per kWh)       1997    1998    1999    2000    2001
- ----------------------------------------------------
PG&E            3.60    3.71    3.83    3.98    4.19

DRA             2.80    2.90    2.95    2.95    3.00

As an alternative, the DRA proposes that the ICIP mechanism be 
replaced by traditional cost of service recovery for Diablo Canyon 
operating costs and capital additions.

In addition to the ICIP, PG&E has proposed a sunk cost revenue 
requirement consisting of PG&E's remaining sunk costs in Diablo Canyon 
at December 31, 1996, depreciated over a five-year period, which would 
be recovered regardless of Diablo Canyon's performance.  The DRA 
recommends various disallowances that would reduce the amount of the 
sunk cost revenue requirement that could be recovered.  In particular, 
the DRA recommends disallowing $78 million in nuclear fuel inventory, 
$40 million in post-2001 tax benefits the DRA alleges should be flowed 
through to ratepayers, and an unspecified amount due to allegedly 
excessive profits PG&E has or may earn on Diablo Canyon generation.

In its report, the DRA adopts PG&E's rate freeze proposal, but 
proposes that residential and small customer rates be reduced by 10% 
over the five-year freeze period.  The DRA states that this 10% rate 
reduction would be in addition to any rate reductions mandated by the 
California State Legislature.

Hearings on the Diablo Canyon/Rate Freeze Application are scheduled 
for October 1996, with a decision currently expected in March 1997.   

		b.  CTC Application

Pursuant to the CPUC's December 1995 electric industry restructuring 
decision, on August 30, 1996, PG&E submitted its application to 
establish a competition transition charge (CTC).  The purpose of the 
application (CTC Application) is to (1) establish a methodology for 
calculating the CTC, (2) identify costs included in the CTC, (3) 
establish the ratemaking mechanism required to recover generation 
costs and the CTC, (4) describe the CTC responsibility for departing 
load and (5) estimate the CTC for calendar year 1998.

PG&E's CTC Application represents another step in the process that 
will ultimately determine the amount of CTC responsibility for each 
customer rate class.  PG&E's CTC proposal is consistent with the goals 
articulated in the CPUC's electric industry restructuring decision and 
reflects the terms of PG&E's Diablo Canyon/Rate Freeze Application.  
In addition, the filing recognizes that electric industry 
restructuring legislation, if enacted, will require PG&E to modify and 
supplement the CTC Application.

CTC Recovery Method:

In its CTC Application, PG&E notes that since it has proposed to take 
on the risk of recovery of its utility generation CTC through its rate 
freeze proposal and accelerated CTC recovery schedule it should have a 
ratemaking mechanism to collect CTC that gives PG&E flexibility in 
recovering CTC and the ability to bring non-nuclear generation assets 
to a level approximating their market value.  PG&E would be at risk 
for completing recovery of PG&E's above-market utility generation-
related investments, including generation plant and related regulatory 
assets by the end of 2001.

Consistent with PG&E's preliminary unbundling proposal, filed with the 
CPUC in July 1995, PG&E proposes to measure CTC revenues on a residual 
basis, (i.e., the costs of distribution, transmission, generation and 
public purpose programs and other non-bypassable charges, such as 
nuclear decommissioning, will be subtracted from the "frozen" bundled 
rates and the amount that remains will be applied to transition 
costs).  Under PG&E's proposal, PG&E would collect all CTC-related 
revenues in a single account that would be used to recover CTC costs 
in the following order:

(1) the current year costs, including the revenue requirement for 
Diablo Canyon sunk costs and the ICIP, revenue requirements associated 
with the depreciation of non-nuclear utility generation plant and QF 
and other power purchase agreements and QF restructuring costs;

(2) accelerated recovery of costs for which CTC recovery must be 
completed by the end of 2001, including generation-related regulatory 
assets, and above-market plant costs; and

(3) CTC costs that may be recovered after 2001, including 
restructuring implementation costs (e.g., ISO, PX and direct access 
implementation costs), employee transition costs, and QF and other 
power purchase agreements revenue requirements and QF restructuring 
costs after 2001.

In its CTC Application, PG&E requests the flexibility to use available 
CTC revenues to recover eligible costs in this priority order in order 
to minimize the potential for write-offs under the proposed shortened 
CTC recovery period.  PG&E indicates that such flexibility is also 
required in order to allow PG&E the opportunity to accelerate non-
nuclear generation plant balances so that the net book value of the 
plant will approximate the plant's market value so as to reduce the 
probability that PG&E would have write-offs due to inconsistent 
treatment between regulation and financial accounting.

If CTC revenues through 2001 are insufficient to recover PG&E's 
uneconomic costs related to its generation plant and related 
regulatory assets, PG&E would incur a loss.  Should CTC revenues 
exceed these costs, they would be used to reduce those CTC costs 
eligible for recovery beyond 2001.

PG&E's proposals in the Diablo Canyon Rate Freeze Application, its 
generation performance-based ratemaking application filed in July 
1996, and the CTC Application would eliminate the need for Energy Cost 
Adjustment Clause reasonableness reviews for generation, power plant 
fuel and power purchase costs.





Costs Included in CTC:

PG&E's filing indicates that CTCs are generally composed of sunk 
costs, ongoing costs and implementation costs.  PG&E proposes to 
include in CTC the following categories of costs:

 (1) Above-market portion of Diablo Canyon;
 (2) Fossil generation sunk costs;
 (3) Future fixed and variable operating costs and future capital
	additions for fossil "constrained-on" generation plants (i.e.,
	fossil plants that are required to operate to maintain 
	transmission system reliability as designated by the ISO) to the 
	extent not recovered under reliability contracts with the ISO;
 (4) Hydroelectric and geothermal generation sunk costs, ongoing 
	operating costs and future capital additions;
 (5) Cost of the sunk cost audit to be completed in connection with
	PG&E's August 1996 sunk cost filing with the CPUC;
 (6) QF and other power purchase agreements;
 (7) Generation-related regulatory assets and obligations;
 (8) ISO, PX and direct access implementation costs;
 (9) Employee transition costs; and 
(10) Generation divestiture transaction costs.

Estimate of CTCs:

PG&E's filing presents an estimate of CTC expected in 1998, assuming 
that the Diablo Canyon/Rate Freeze Application and CTC provisions of 
the Restructuring Agreement are approved by the CPUC.  Assuming a 
market price of $0.026 per kWh in 1998, PG&E expects that CTC in 1998 
will range from $2.2 billion (PG&E's current year costs for 1998) to 
$2.8 billion (which would include accelerated recovery of non-nuclear 
generation plant and regulatory assets).

Any estimate of CTCs constitutes a forward-looking statement.  Certain 
factors, including most importantly, actual market prices in the 
future and future valuation of generation assets in a restructured 
market, may cause actual results to differ materially from those 
anticipated in those forward-looking statements.

CTC Responsibility for Departing Loads:

PG&E's filing proposes a separate CTC ratemaking mechanism for 
"departing load" customers, i.e., those customers who discontinue 
their purchases of electricity supplied or delivered by PG&E and 
replace that usage with electricity that is both supplied and 
delivered by some other means.  PG&E proposes that CTC be collected 
from those customers using a combination of ongoing and lump sum 
payments.  

2.  1997 Cost of Capital

On August 26, 1996, the DRA, PG&E and all other active parties agreed 
to jointly recommend a return on common equity (ROE) of 11.60% for 
PG&E's authorized cost of capital for 1997, which represents no change 
from PG&E's currently authorized ROE.  PG&E had originally requested 
an ROE of 11.85%, while the DRA had recommended 11.25%.  The joint 
recommendation also recommends adoption of a capital structure of 
48.0% common equity, 5.8% preferred stock and 46.2% long-term debt, 
which is a slight change from the current capital structure of 48.0% 
common equity, 5.5% preferred stock and 46.5% long-term debt.  When 
combined with the estimated costs of debt and preferred stock, the 
recommended 11.60% return on common equity results in an overall rate 
of return on utility rate base of 9.45% for 1997, compared with the 
9.49% authorized for 1996.

If the joint recommendation is adopted, PG&E's electric and gas 
revenues would decrease approximately $5 million and $2 million, 
respectively.  PG&E has requested that the electric revenue changes 
associated with the cost of capital proceeding and other outstanding 
rate proceedings be consolidated in order to achieve the customer 
electric rate freeze proposed by PG&E in the Diablo Canyon/Rate Freeze 
Application.

As part of its cost of capital application, PG&E had requested a 
separate capital structure and cost of capital for PG&E's portion of 
the PGT/PG&E Pipeline Expansion (PG&E Expansion).  The joint 
recommendation specifies an ROE of 11.60%, with a capital structure of 
64% debt and 36% equity.  PG&E's current ROE for the PG&E Expansion is 
12.1%, with a capital structure of 67% debt and 33% equity, and it had 
requested a 13.5% ROE for 1997.  Adoption of the joint recommendation 
is not expected to result in any change in revenue from the PG&E 
Expansion.






Agreements with the DRA do not constitute a CPUC decision and are 
subject to modification by the CPUC in its final decision.  A final 
CPUC decision on the parties' joint recommendation is expected in 
November 1996.  


			      PACIFIC GAS AND ELECTRIC COMPANY


				 GORDON R. SMITH   
							  
			      By ________________________________
				 GORDON R. SMITH
				 Senior Vice President and 
				 Chief Financial Officer




Dated: September 9, 1996