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: March 30, 2001
Exact Name of
Commission Registrant State or other IRS Employer
File as specified Jurisdiction of Identification
Number in its charter Incorporation Number
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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.
A. Recent Regulatory Actions
On March 27, 2001, the California Public Utilities Commission
(CPUC) issued a decision in the rate stabilization proceeding of Pacific
Gas and Electric Company (Utility), the California subsidiary of PG&E
Corporation, authorizing the Utility to add an average 3 cent per
kilowatt hour (kWh) surcharge to current rates, in addition to the
emergency 1 cent per kWh surcharge adopted by the CPUC on January 4,
2001, and made permanent by the March 27, 2001 decision. Although the
increase is authorized immediately, the 3 cent per kWh surcharge will
not be collected in rates until the CPUC establishes an appropriate rate
design for the surcharge, which is not expected to be adopted until May
2001. The revenue generated by the rate increase is to be used only for
electric power procurement costs that are incurred after March 27, 2001.
The rate increase is subject to refund (1) if not used to pay for such
power purchases, (2) to the extent that generators and sellers of power
make refunds for overcollections, or (3) to the extent any
administrative body or court denies the refunds of overcollections in a
proceeding where recovery has been hampered by a lack of cooperation
from the Utility. In addition, the CPUC ordered that the 3 cent per KWh
surcharge be added to the rate paid to the California Department of
Water Resources (DWR) as ordered in the CPUC decision discussed below.
Also, on March 27, 2001, the CPUC issued a decision ordering the
Utility and the other California investor-owned utilities to pay the DWR
a per-kWh price equal to the applicable generation-related retail rate
per kWh established for each utility as in effect on January 5, 2001,
for each kWh the DWR sells to the customers of each utility. The CPUC
determined that the generation-related component of retail rates should
be equal to the total bundled electric rate (including the 1 cent per
kWh interim surcharge adopted by the CPUC on January 5, 2001) less the
following non-generation-related rates or charges: transmission,
distribution, public purpose programs, nuclear decommissioning, and the
fixed transition amount. The CPUC determined that the Utility's
company-wide average generation-related rate component is 6.471 cents
per kWh and that this is the amount that should be paid to the DWR for
each kWh delivered by the DWR to the Utility's retail customers after
February 1, 2001, until specific rates are calculated. The CPUC ordered
the utilities to pay the DWR within 45 days after the DWR supplies power
to their retail customers, subject to penalties for each day that
payment is late. The amount of power supplied to retail end-use
customers after January 31, 2001, for which the DWR is entitled to be
paid would be based on the product of the number of kWh that the DWR
provided 45 days earlier and the Utility's company-wide average
generation-related rate of 6.471 cents per kWh, and the additional 3
cent per kWh surcharge described above.
The CPUC also ordered that the utilities immediately pay the sums
owing the DWR for power sold by the DWR from January 18, 2001 through
January 31, 2001, under Senate Bill 7X. Based on an estimated number of
kWh sold by the DWR, the Utility paid approximately $30 million to the
DWR at the rate of 5.471 cents per kWh as adopted by the CPUC.
In addition, the decision proposed a method by which the
California Procurement Adjustment (as described in Public Utilities Code
Section 360.5 added by Assembly Bill 1X effective February 1, 2001)
should be calculated. Section 360.5 requires the CPUC to determine (1)
the portion of each electric utility's electric retail rate effective on
January 5, 2001, the "California Procurement Adjustment" or CPA, that is
equal to the difference between the generation-related component of the
utility's retail rate in effect on January 5, 2001, and the sum of the
costs of the utility's own generation, qualifying facilities (QFs)
contracts, existing bilateral contracts (i.e., entered into before
February 1, 2001), and ancillary services, and (2) the amount of the CPA
that is allocable to the power sold by the DWR. The CPUC has proposed
that the CPA should be a set rate calculated by determining each
utility's generation-related revenues (for the Utility the CPUC has
proposed that this be equal to 6.471 cents per kWh multiplied by total
kWh sales by the Utility to the Utility's retail customers), then
subtracting each utility's statutorily authorized generation-related
costs, and dividing the result by each utility's total kWh sales. Each
utility's CPA rate will be used to determine the amount of bonds the DWR
may issue.
In response to the CPUC's request, the Utility filed comments on
the proposed CPA calculation method on March 29, 2001. The Utility
believes the proposed method is unlawful and inconsistent with Section
360.5 because it does not allow for recovery of the Utility's own
revenue requirements and costs of service. Using the CPUC's proposed
methodology, the Utility's calculations show that the CPA for the 11-
month period February through December 2001 would be negative by $2.2
billion, (i.e., there would be no CPA available to the DWR) assuming the
DWR purchases 84 percent of the Utility's net open position. (The net
open position is the amount of power that cannot be met by the
utilities' own or contracted-for generation.) If AB 1X were amended to
also include in the CPA all the incremental revenue from the 3 cent per
kWh increase discussed above (approximately $2.3 billion for 11 months),
then the amount available to the DWR for the CPA for the comparable 11-
month period would be approximately $100 million. The CPUC has
indicated that it will adopt a CPA calculation method at its
continuation meeting on April 3, 2001.
The CPUC noted that although the DWR has assumed responsibility to
purchase some of the utilities' power requirements, it has not committed
to purchase all of the utilities' net open position. To the extent the
DWR does not buy enough power to cover the Utility's net open position,
the California Independent System Operator (ISO) purchases emergency
power on the high-priced spot market to meet system reliability
requirements and the net open position. The ISO may attempt to charge
the Utility a proportionate share of the ISO's purchases. The Utility
believes that under the current circumstances and applicable tariffs it
is not responsible for such ISO charges. As the DWR has not advised the
CPUC of its revenue requirement for the DWR's power purchases, it is
unclear how much of the 3 cent surcharge will be needed by the DWR and
how much, if any, may be used by the Utility to recover its procurement
costs incurred after March 27, 2001 (including any ISO charges).
Since the end of January 2001, the Utility has been paying only 15
percent of amounts due QFs. On March 27, 2001, the CPUC issued a
decision requiring the Utility and the other California investor-owned
utilities to pay QFs fully for energy deliveries made on and after the
date of the decision, within 15 days of the end of the QFs' billing
period. The decision permits QFs to establish a 15-day billing period
as compared to the current monthly billing period. The CPUC noted that
its change to the payment provision was required to maintain energy
reliability in California and thus provided that failure to make a
required payment would result in a fine in the amount owed to the QF.
The decision also adopts a revised pricing formula relating to the
California border price of gas applicable to energy payments to all QFs,
including those that do not use natural gas as a fuel. Based on the
Utility's preliminary review of the decision, the revised pricing
formula would reduce the Utility's 2001 average QF energy and capacity
payments from approximately 12.7 cents per kWh to 12.3 cents per kWh.
The CPUC also adopted The Utility Reform Network's (TURN) proposal
to transfer on a monthly basis the balance in each utility's transition
revenue account (TRA) to the utility's transition cost balancing account
(TCBA). The TRA is a regulatory balancing account that is credited with
total revenue collected from ratepayers through frozen rates and which
tracks under-collected power purchase costs. The TCBA is a regulatory
balancing account that tracks the recovery of generation-related
transition costs. The accounting changes are retroactive to January 1,
1998. The Utility believes the CPUC is retroactively transforming the
power purchase costs in the TRA into transition costs in the TCBA.
However, the CPUC characterized the accounting changes as merely
reducing the prior revenues recorded in the TCBA, thereby affecting only
the amount of transition cost recovery achieved to date. The CPUC also
ordered that the utilities restate and record their generation
memorandum accounts balances to the TRA on a monthly basis before any
transfer of generation revenues to the TCBA. The CPUC found that based
on the accounting changes, the conditions for meeting the end of the
rate freeze have not been met.
The Utility believes the adoption of TURN's proposed accounting
changes results in illegal retroactive ratemaking and constitutes an
unconstitutional taking of the Utility's property, and violates the
federal filed rate doctrine. The Utility also believes the other CPUC
decisions are similarly illegal to the extent they would compel the
Utility to make payments to the DWR and QFs without providing adequate
revenues for such payments. The Utility plans to challenge the
decisions in appropriate legal forums.
B. Accounting Treatment
Under the 1996 electric industry restructuring legislation,
Assembly Bill 1890, most transition costs must be collected by December
31, 2001. Under a prior CPUC decision, any costs incurred during the
transition period but not recovered before the end of the transition
period are not recoverable from customers. Statement of Financial
Accounting Standards No. 71 (FAS 71), "Accounting for the Effects of
Certain Types of Regulation," permits the Utility to defer costs as
regulatory assets if such costs are determined to be probable of
recovery in future rates. If the Utility determines that regulatory
assets are no longer probable of recovery through regulated rates, they
must be written off. Transition costs may only be recovered through the
competition transition charge (the amount of revenues remaining after
paying authorized operating costs), the excess of market value of
generating assets over book value, and retained generation revenues.
Power procurement costs are recoverable only from revenues from frozen
rates. Power procurement costs for the remainder of 2001 and
amortization of remaining transition costs are expected to exceed
revenues from retail rates provided for recovery of such costs. As a
result, absent a regulatory or legislative solution that provides for
full recovery of such costs, the Utility's and PG&E Corporation's
financial results for the fourth quarter and the fiscal year ended 2000
would include a charge of approximately $6.9 billion ($4.1 billion after
tax), reflecting a write-off of the TRA and TCBA as of December 31,
2000. Further, the Utility does not have authority to recover any power
purchase costs it incurs during 2001 in excess of revenues from retail
rates. Such amounts also would be charged against earnings absent a
regulatory or legislative solution that provides for full recovery of
such costs. For financial reporting purposes only, this would result in
a material decline in reported common stockholders' equity, potentially
below zero for the Utility during the first quarter of 2001, assuming
the ISO continues to charge the Utility for the amount of the Utility's
net open position not met through the DWR's purchases.
Under FAS 71, if a rate mechanism provided by legislation or other
regulatory authority were subsequently established that made recovery
from regulated rates probable as to all or a portion of the
undercollection that was previously charged against earnings, a
regulatory asset would be correspondingly reinstated with a
corresponding increase in earnings.
Due to the CPUC's adoption of TURN's proposal concerning various
accounting changes and the need for PG&E Corporation and the Utility to
evaluate the CPUC decisions described above, PG&E Corporation and the
Utility intend to file a notice with the Securities and Exchange
Commission (SEC) pursuant to SEC Rule 12b-25 that each entity is unable
to timely file its Annual Report on Form 10-K by the due date, April 2,
2001, and that each entity will file the report no later than April 17,
2001.
C. Liquidity and Financial Position
At March 29, 2001, the Utility's cash reserves are $2.6 billion.
If the Utility were current with all payments to its creditors
(including the $938.5 million balance of its bank loans which the
lenders have agreed to forbear from accelerating until April 13, 2001),
the cash position would be negative $1.8 billion. As previously
reported, the Utility has temporarily suspended the payment of certain
obligations. Through April 30, 2001, the Utility expects to have an
aggregate of approximately $1.5 billion of additional obligations that
will become due and payable, including an estimated (1) $550 million to
the ISO, (2) $340 million to QFs, and (3) $470 million to gas suppliers.
Based on a preliminary estimate that is subject to revision, as of
February 28, 2001, the Utility's under-collected balance in its TRA was
approximately $8.9 billion. This amount reflects estimated charges from
the ISO for power purchased through February 2001 to meet the amount of
the Utility's net open position not met through the DWR's purchases.
The Utility has included certain costs in its estimated TRA balance
although the Utility believes it may not be responsible for such costs,
including charges from the ISO for power purchases in those cases where
the DWR did not purchase power to cover the Utility's net open position
and charges for an allocated portion of defaulted payments owed to the
California Power Exchange by another California investor-owned utility.
Until the treatment of these costs is clarified, the Utility has
included them in its estimated TRA balance. Under the CPUC's
interpretation of AB 1X, the DWR is not responsible to purchase the
Utility's entire net open position. Under this interpretation, it is
likely that the ISO will continue to charge the Utility for power
purchased by the ISO for delivery to the Utility's customers causing the
TRA balance to grow.
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: CHRISTOPHER P. JOHNS
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CHRISTOPHER P. JOHNS
Vice President and Controller
PACIFIC GAS AND ELECTRIC COMPANY
By: KENT M.HARVEY
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KENT M. HARVEY
Senior Vice President, Chief Financial
Officer, and Treasurer
Dated: March 30, 2001