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: December 29, 2000

            Exact Name of
Commission  Registrant        State or other   IRS Employer
File        as specified      Jurisdiction of  Identification
Number      in its charter    Incorporation    Number
- ----------  --------------    ---------------  --------------

1-12609     PG&E Corporation  California       94-3234914

1-2348      Pacific Gas and   California       94-0742640
            Electric Company




Pacific Gas and Electric Company    PG&E Corporation
77 Beale Street, P.O. Box 770000    One Market, Spear Tower, Suite 2400
San Francisco, California  94177    San Francisco, California 94105

(Address of principal executive offices) (Zip Code)


Pacific Gas and Electric Company    PG&E Corporation
(415) 973-7000                     (415) 267-7000

    (Registrant's telephone number, including area code)



Item 5.  Other Events.

California Energy Crisis

On December 27, 2000, emergency hearings began in the post
transition period electric ratemaking proceedings of Pacific Gas and
Electric Company (Utility) pending before the California Public
Utilities Commission (CPUC).  In connection with the hearings, the
Utility submitted additional testimony in support of its rate
stabilization plan filed with the CPUC on November 22, 2000.

Current Financial Condition.  In the testimony, the Utility stated that
based on existing cash reserves, estimated receipts from customer bills
and power market transactions, and normal payment schedules, it expects
to utilize all of its cash reserves within the next three to seven
weeks, and run out of cash by late January or early February 2001,
assuming no electric rate increase or additional financing.  The Utility
also stated that it does not expect that it will be able to borrow funds
absent clear CPUC actions to ensure recovery of the Utility's power
procurement costs.  The Utility's most recent estimate is that December
2000 prices will average more than $400 per megawatt hour (MWh). The
Utility estimates that spot power market (i.e., real time energy) prices
for 2001 will average over $180 MWh.  The Utility noted that it expects
this increase will cause the price the Utility pays qualifying
generators (QFs) under long-term power purchase contracts to rise, as
more QFs elect to receive PX prices instead of their short-term avoided
cost payments otherwise due under the contracts.

In the testimony, the Utility noted that although it has current cash
reserves of $1.2 billion, it has payments due to the California
Independent System Operator (ISO) on January 3 and February 1, 2001 for
real-time energy purchases of $438 million and $583 million,
respectively.  In addition, the Utility estimates that its payment to
the California Power Exchange (PX), due on February 15, 2001 for day-
ahead energy purchases, will be $431 million.  The Utility estimates
that its payment to the ISO for energy purchases in December 2000, which
is due on March 2, 2001, will be $1.7 billion.  The Utility also noted
that its monthly gas procurement disbursements are more than $200
million.  (Although gas costs are recovered in full from customers,
there is a lag of time between when the Utility pays for the gas and
when the Utility receives revenues from customers for such gas costs.)
The Utility noted that creditors have begun to demand advance payment in
return for deliveries of natural gas and power, and that if such demands
continue, the Utility expects to completely exhaust its cash reserves by
the third week of January 2001.  The Utility is evaluating what
additional steps it would need to take to preserve its ability to
continue serving its customers.  The Utility must either raise
substantial sums of new capital or default on its payment obligations.
The Utility's cash deficit will total $4.8 billion through the end of
the first quarter of 2001, assuming no electric rate increase, continued
access to normal trade credit, and retention of its credit facilities.
Excluding the $1.2 billion cash on hand, this would result in a
financing requirement of $3.6 billion.  If the Utility were unable to
access its credit facilities because of an event of default, such as a
significant ratings downgrade, the Utility would need to raise an
additional approximate amount of $2 billion to pay maturing commercial
paper and repay draws on its facilities.

End of Rate Freeze.  The Utility's testimony also notes that because the
Utility's revenues from its generation facilities has been credited to
its transition cost balancing account (TCBA) and generation memorandum
accounts which track the recovery of the Utility's transition costs, the



Utility will have recovered all of its transition costs by the end of
December 2000, even assuming the value of the Utility's hydroelectric
generation assets is equal to book value (approximately $700 million).
To the extent the value of the hydroelectric assets is greater, the
transition period would have ended sooner.  Assuming a value of $4
billion (as supported by the Utility's updated testimony in the
proceeding to value the hydroelectric assets), the transition period
would have ended in April 2000.  Therefore, the Utility does not believe
that the CPUC needs to wait for a final market valuation of the
Utility's hydroelectric assets before finding that the rate freeze has
ended.

Requested Rate Increase.  The Utility submitted revised testimony on
December 22, 2000, in its rate stabilization plan requesting an initial
average rate increase of  26 percent, reflecting a rate component for
current net power purchase costs for residential and small commercial
customers capped at approximately 6.5 cents per kilowatt hour.  This
initial rate increase also reflects larger customers paying the
Utility's actual cost of power, estimated in the rate stabilization plan
based on recorded data through September 2000. Under the Utility's rate
stabilization plan, this initial rate increase and subsequent rate
increases are intended to recover the Utility's future power procurement
costs and the under-collected power procurement costs.  The initial rate
increase is subject to an automatic increase of up to a maximum of 2
cents per Kwh per  year as well as an additional annual upward
adjustment, if actual power cost under-collections are higher than
expected.   The increased revenues from customers which would be
collected under the rate stabilization plan would improve the Utility's
ability to pay its ongoing net power purchase costs. However, based on
current forward prices in the wholesale power market, the Utility would
be required to obtain financing to pay the difference between the amount
of revenues collected and the amount the Utility pays for power.

Retained Generation Facilities.  Finally, the Utility's testimony
included the Utility's proposals with respect to its retained generation
facilities to address the CPUC's question, raised in its December 22,
2000 order, whether power produced from retained generation assets
should serve the utilities' customers and, if so, what ratemaking such
actions would entail.  The Utility proposed that for the next two years
(after which the Utility expects the current supply shortage will be
less critical), the Utility retain its generation facilities and sell
the output of these facilities directly to its bundled customers on an
incentive ratemaking basis to lower the costs of procured power for such
customers. (Bundled customers are those that continue to choose the
Utility as their generation provider, in contrast to direct access
customers who have chosen an alternative generation provider.)

For the hydroelectric facilities, the Utility has proposed to modify its
rate stabilization plan proposal for these facilities to sell the output
directly to retail customers for two years at a cost of service price,
derived using the revenue sharing agreement (RSA)(submitted in
connection with the application for approval of a settlement agreement
involving the valuation and disposition of the hydroelectric assets
which the Utility no longer supports) as a framework.  The RSA would be
modified to eliminate the revenue sharing concept for this two-year
period but the method for determining cost of service and return would
be retained.  During this two-year period, the 10 percent shareholder
share of foregone market revenues will be tracked in a regulatory
balancing account by imputing revenues (in excess of costs) that would
have been earned under a reasonably-based market price benchmark.  These
foregone revenues would be recaptured from market revenues or future
sales to bundled customers.  Following the two-year period, the 90/10



sharing would resume under the RSA.  At that point, assuming the market
is functioning properly, the Utility would sell its generation into the
market and share with ratepayers 90 percent of net market revenues.
During the initial two-year period, the Utility proposed that the
settlement value of $2.8 billion be used as minimum valuation to
calculate the hydroelectric cost of service under the RSA, provided that
the rates for hydroelectric power are trued-up to reflect the final
value of the assets (and to recover any additional depreciation and
return).

With respect to the Utility's Diablo Canyon Nuclear Power Plant (Diablo
Canyon), the Utility proposed to continue to sell its power from Diablo
Canyon directly to its retail customers at the 2001 Incremental Cost
Incentive Price (ICIP), 3.49 per KWh, for the next two years.  Similar
to the proposal made in the Utility's rate stabilization plan, the
Utility has proposed that during this two-year period, the 50 percent
shareholder share of foregone market revenues will be tracked in a
regulatory balancing account by imputing net revenues (in excess of
costs) that would have been earned under a reasonably-based market price
benchmark.  These foregone revenues will be recaptured from market
revenues or future sales to bundled customers.  Following the two-year
period of ICIP pricing, assuming the market is functioning properly, the
Utility would sell into the market and share with ratepayers 50 percent
of net market revenues.

During the hearings, testimony was also given regarding PG&E
Corporation's financial liquidity.  PG&E Corporation currently has cash
reserves of $307 million.  If PG&E Corporation's and the Utility's
credit ratings were to suffer a  downgrade below investment grade, such
a downgrade would constitute an event of default under PG&E
Corporation's $ 436 million short-term and $500 million long-term
revolving credit facilities and would constitute an event of default
under the Utility's $850 million short-term revolving credit facility.
Such a default would entitle the lenders to accelerate approximately
$185 million of debt outstanding under PG&E Corporation's facilities.
In addition, the downgrade of PG&E Corporation's long-term debt below
investment grade by both Standard & Poor's and Moody's Investor Service,
Inc., and the failure by PG&E
Corporation to provide an acceptable letter of credit in the required
amounts within the required time periods, would constitute an event of
default under various capital infusion agreements.  Upon an event of
default under these agreements, PG&E Corporation would be obligated to
pay an aggregate amount of at least $1 billion.  The ratings downgrade
would also adversely affect other PG&E Corporation and Utility
outstanding debt securities, financing agreements and relationships.
PG&E Corporation and the Utility believe that a ratings downgrade would
preclude the ability of PG&E Corporation and the Utility to issue
commercial paper and similar financial instruments.  In addition, PG&E
Corporation is the guarantor of obligations of its energy trading
subsidiaries, PG&E Energy Trading-Power, L.P., PG&E Energy Trading-Gas
Corporation, and PG&E Energy Trading-Canada Corporation, in the
aggregate amount of up to $2.8 billion.  Under many of the underlying
trading agreements, the downgrade of PG&E Corporation's long-term debt
below investment grade would entitle the counter-parties to demand
substitute credit support from the energy trading subsidiaries.  If the
subsidiaries were unable to provide adequate substitute credit support,
the counter-parties may declare a default, terminate the agreement, and
make a claim under the parent guarantee.  If claims were made under a
substantial portion of the outstanding guarantees, PG&E Corporation may
be unable to timely honor the guarantees.



                                 SIGNATURE


Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by
the undersigned thereunto duly authorized.



                         PG&E CORPORATION

                         By    BRUCE R. WORTHINGTON
                               ---------------------
                               BRUCE R. WORTHINGTON
                               Senior Vice President and General Counsel


                               PACIFIC GAS AND ELECTRIC COMPANY

                               By    DINYAR B. MISTRY
                                     ------------------------------
                               DINYAR B. MISTRY
                               Vice President and Controller




Dated: December 29, 2000