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: October 25, 2000
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)
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Item 5. Other Events
A. Third Quarter 2000 Consolidated Earnings (unaudited)
On October 24, 2000, PG&E Corporation reported diluted earnings per common
share of $.67 from continuing operations for the three months ended
September 30, 2000. PG&E Corporation's Condensed Statement of Consolidated
Income for the three months ended September 30, 2000, is attached hereto as
Exhibit 99.
B. Pacific Gas and Electric Company's Wholesale Power Purchase Costs
As previously disclosed, due to the high wholesale power prices at which
Pacific Gas and Electric Company (Utility), the California utility
subsidiary of PG&E Corporation, purchases power for its electric
distribution customers from the California Power Exchange (PX) and the
California Independent System Operator (ISO), the Utility has deferred for
future recovery the amount of its costs that exceed revenues collected from
frozen rates. Continuing the high prices seen since June 2000, the average
price the Utility was charged for electric power in the month of September
2000, was approximately 14 cents per kilowatt-hour (kWh), compared to
approximately 4 cents per kWh during the same period in 1999.
At September 30, 2000, the under-collected balance of these wholesale power
purchase costs recorded in the Utility's regulatory balancing account (the
Transition Revenue Account or TRA) was approximately $2.9 billion. The TRA
balance does not reflect the Utility's revenues from (i) Utility-owned
generation sales to the PX in excess of authorized costs, nor (ii) Utility
sales of other generation to the PX from Qualifying Facilities (QFs) and
other power providers in excess of the Utility's costs to purchase such
power. (Approximately half of the Utility's suppliers under QF contracts
have elected to receive PX-based prices for energy in addition to
contractual capacity payments. The Utility expects that most remaining QF
generators will elect to receive PX prices for their energy payments by
summer 2001. The Utility pays these suppliers directly, rather than
through the PX, but receives billing credits for energy delivered to the PX
from QFs.) For accounting and ratemaking purposes and as required by the
California electric industry restructuring law, during the transition
period, the amount of PX revenues from Utility-owned generation in excess
of authorized costs and from other generation sources in excess of the
price the Utility pays to purchase such power, are applied as a credit to
the Utility's transition costs (generation-related costs and obligations
that prove to be uneconomic under the new market structure) and are not
used to offset the TRA under-collection.
The Utility has been required to finance the majority of its net power
purchase costs because the Utility's purchased power costs have greatly
exceeded the revenues from the Utility's sales to the PX. Since the
purchased power costs are expected to continue to exceed the revenues from
the Utility's sales to the PX, the Utility's financing needs are expected
to continue to grow until rates are adjusted to permit recovery of these
costs. The Utility has fully utilized its existing $1 billion revolving
credit facility to support the Utility's commercial paper program and other
liquidity requirements. On October 18, 2000, the Utility executed a credit
agreement for an additional $1 billion in revolving credit facilities to
provide commercial paper backup to support its higher purchased power costs
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and the associated increases in the TRA. On October 19, 2000, the CPUC
approved the Utility's request to increase its current authorized amount of
short-term debt by $1.4 billion, raising the Utility's short-term debt
authority to $3.1 billion. The additional $1.4 billion may only be used
for the purpose of financing the purchase of wholesale power for delivery
to the Utility's retail customers. The Utility also is pursuing up to $1.3
billion of additional short and long-term debt financing in the capital
markets. Additionally, the Utility has filed a request with the CPUC
requesting authority to issue an additional $2 billion in long-term debt
instruments. The Utility's ability to meet its obligations as they come
due will depend in significant part upon the extent to which regulatory
bodies allow the Utility to recover in rates its wholesale power purchase
costs.
As previously disclosed, a prior CPUC decision would prohibit the Utility
from collecting after the transition period certain electric costs incurred
during the transition period but not recovered from frozen rates during
that period, including the under-collected purchased power costs recorded
in the TRA. The CPUC decision would also prohibit offsetting these
specific under-collected amounts against over-collected transition costs.
The Utility's petition for review of this decision by the California
Supreme Court is pending. Further, on October 4, 2000, the Utility filed
an emergency petition with the CPUC to modify the prior CPUC decision to
permit the Utility to carry over beyond the end of the transition period
the amounts recorded in the TRA and to recover these amounts over a
reasonable period through retail electric rates. On October 17, 2000, the
assigned CPUC commissioner and administrative law judge issued a ruling in
response to the emergency petition stating they will reconsider the
accounting mechanisms established by prior CPUC decisions and adopt a
schedule that permits a decision by the end of the year.
In response to the above ruling, on October 25, 2000, the Utility filed its
proposals and a procedural schedule that will be considered by the CPUC at
a prehearing conference on October 27, 2000. The Utility requested that
the CPUC modify its prior decisions to authorize the utilities to transfer
any unrecovered balance in the TRA as of the end of the rate freeze into a
new balancing account, and authorize recovery of the balance in that new
account over a period not to exceed four years, subject to a rate
stabilization plan to be addressed in a second phase of the proceeding.
The Utility asked the CPUC to adopt an expedited procedural schedule in a
second phase that would, not later than March 31, 2001, resolve the
following issues: (1) implementation of when and how the rate freeze is to
be ended; (2) adoption of post rate freeze tariffs and rates; (3) approval
of the rate stabilization plan; and (4) adoption of the retail rate
components for recovery of the new balancing account. The Utility
indicated that it will submit its detailed proposals on the rate
stabilization plan and tariffs by November 15, 2000.
The Utility is reviewing on an ongoing basis the facts and circumstances
relating to the TRA under-collections. The applicable accounting standards
permit the TRA under-collections to be recorded as a regulatory asset on
the balance sheet rather than being charged to earnings if it is probable
that these under-collections will be recovered through the ratemaking
process. The Utility currently believes recovery of the TRA under-
collection is probable. However, ultimate recovery is dependent upon the
favorable outcome of the regulatory matters discussed above, as well as
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other factors such as future market prices of electricity and future fuel
prices.
The Utility is actively exploring ways to reduce its exposure to the higher
power purchase costs and its corresponding TRA balance, including working
with interested parties to address power market dysfunctions before
appropriate regulatory bodies and hedging a portion of its open procurement
position against higher power purchase costs through forward purchases. In
October 2000, the Utility entered into bilateral power purchase contracts
with several suppliers.
On October 16, 2000, the Utility joined with Southern California Edison and
the consumer group The Utility Reform Network (TURN) in filing a petition
with the Federal Energy Regulatory Commission (FERC) requesting that the
FERC (1) immediately find the California wholesale electricity market to be
not workably competitive and the resulting prices to be unjust and
unreasonable; (2) immediately impose a cap on the price for energy and
ancillary services; and (3) institute further expedited proceedings
regarding the market failure, mitigation of market power, structural
solutions, and responsibility for refunds. However, the reduced price cap
requested, even if approved, would still be above the approximate 5.4 cents
per kWh embedded in frozen rates for the payment of the Utility's wholesale
power purchase costs. Also, on October 20, 2000, the ISO filed a market
stabilization plan with the FERC requesting the FERC to impose a price cap
of $100 per megawatt hour (10 cents per kWh) for generators who do not
enter into contracts to supply 70 percent of their supply to serve
California customers. There are certain other exemptions to the $100 price
cap. The existing $250 price cap per megawatt hour would remain in effect
for generators who are exempt from the $100 per megawatt hour price cap.
The ISO also has recommended that utilities and other buyers be required to
contract for 85 percent of their customer requirements for power in advance
of when the power is needed.
C. Transition Cost Recovery
The Utility tracks the amount of transition costs that must be recovered
during the transition period in a regulatory balancing account called the
transition cost balancing account or TCBA. Under the electric industry
restructuring law, when the Utility has recovered its eligible transition
costs, the conditions for terminating the rate freeze and ending transition
period will have been satisfied. At August 31, 2000, consistent with
existing transition costs recovery procedures adopted by the CPUC, the
Utility credited its TCBA by $2.1 billion, the amount by which the
settlement value of the hydroelectric assets exceeded the aggregate book
value of such assets. The Utility also established a separate regulatory
asset in the same amount to reflect the settlement value. The accounting
entries were based on the value used in the proposed settlement filed with
the CPUC in August 2000, regarding the valuation and disposition of these
assets. Based on the credit made to the TCBA and under current CPUC
accounting procedures, the Utility would have completed collection of all
transition costs that must be collected during the transition period as of
August 2000. If the hydroelectric assets were to be sold or valued at a
higher amount, the Utility's transition costs would have been recovered as
of an earlier date when the TRA balance was lower. Testimony taken to date
in the CPUC proceeding in which valuation is to be established put the
range of market values from $2.4 billion to in excess of $3 billion under
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operating and market conditions prior to June 2000. The CPUC is not likely
to consider the Utility's proposed settlement until next year, and it is
uncertain at this time whether the settlement will be approved, modified or
rejected, or withdrawn. Further, on October 16, 2000, the CPUC issued a
ruling re-opening the hydroelectric valuation proceeding to obtain more
information from parties about market valuation in light of the different
market conditions experienced during the summer of 2000. That new
testimony is to be submitted in December 2000 with further testimony and
evidentiary hearings scheduled for next year. The accounting entries
discussed above are subject to later adjustment based on the final
valuation of the hydroelectric assets adopted by the CPUC.
During the transition period, the Utility is required to continue to use
the transition period accounting mechanisms discussed above. This requires
that revenues from sales to the PX of Utility-owned generation and
generation from QFs and other providers in excess of costs be credited to
the TCBA. In addition, the TCBA balance includes a credit for the amount
of PX revenues from the Utility's sale of generation from the Diablo Canyon
nuclear power plant to the PX that exceed revenues from the fixed
Incremental Cost Incentive Price ("ICIP). (During 2000, the ICIP is 3.43
cents per kWh.) After taking into account the credit for the hydroelectric
assets described above, at September 30, 2000, the Utility's TCBA had a
credit balance of approximately $585 million. The amounts discussed above
are subject to adjustment by the CPUC. Further, as mentioned above, the
CPUC has issued a ruling indicating that it would reconsider certain of
these accounting mechanisms noting that the CPUC has the authority to
implement any necessary changes to the electric restructuring accounting
provisions and cost recovery consistent with statutory requirements.
D. Earnings Outlook
PG&E Corporation expects its 2000 earnings per share (EPS) will reach
between $2.50 and $2.55, exceeding its previously announced annual growth
target of 8-10 percent by several percentage points. For 2001, PG&E
Corporation expects its EPS to reach between $2.70 to $2.75, reflecting its
stated 8-10 percent annual growth rate target. These estimates, which are
based on assumptions management believes are reasonable, are forward
looking statements that are subject to numerous risks and uncertainties
that could cause actual results to differ materially from those estimated
or expected. PG&E Corporation can give no assurance that such expectations
and assumptions will prove to have been correct. Although PG&E Corporation
is unable to identify all the risk factors that could affect future results
of operations and financial condition, some of the risk factors include:
- regulatory changes, including the pace and extent of the ongoing
restructuring of the electric and natural gas industries across the
United States;
- future sales levels and economic conditions;
- the amount and method of recovery from customers of the under-collected
electric procurement costs recorded in the Utility's TRA;
- what regulatory, judicial, or legislative actions may be taken to
mitigate the higher power prices in California;
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- the method and timing of disposition and valuation of the Utility's
hydroelectric generation assets;
- the timing of the completion of the Utility's transition cost recovery
and the consequent end of the current electric rate freeze in
California;
- any changes in the amount of transition costs the Utility is allowed to
recover from its customers;
- future operating performance at the Utility's Diablo Canyon Nuclear
Power Plant;
- the method adopted by the CPUC for sharing the net benefits of operating
Diablo Canyon with ratepayers and the timing of the implementation of
the adopted method;
- the extent of anticipated growth of transmission and distribution
services in the Utility's service territory;
- the success of management's strategies to maximize shareholder value in
PG&E National Energy Group, which may include acquisitions or
dispositions of assets, or investments in emerging companies or new
businesses;
- the extent to which our current or planned generation development
projects are completed and the pace and cost of such completion;
- generating capacity expansion and retirements by others;
- the outcome of the Utility's various regulatory proceedings, including
the proceeding to determine the value of the Utility's hydroelectric
generation assets, the electric transmission rate case applications,
post-transition period ratemaking proceedings, the 2001 attrition rate
adjustment request, the cost of capital application, and the 2002
General Rate Case;
- future market prices for electricity and future fuel prices which, in
part, are influenced by future weather conditions and the availability
of hydroelectric power;
- fluctuations in commodity, gas, natural gas liquid, and electricity
prices and the ability to successfully manage such price fluctuations;
- the pace and extent of competition in the California generation market
and its impact on the Utility's costs and resulting collection of
transition costs;
- the effect of compliance with existing and future environmental laws,
regulations, and policies, the cost of which could be significant; and
- the outcome of pending litigation.
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Item 7. Exhibits
Exhibit 99 Condensed Statement of Consolidated Income for the three
months ended September 30, 2000
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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
KENT M. HARVEY
By --------------------
KENT M. HARVEY
Senior Vice President, Treasurer,
Chief Financial Officer, and
Controller
Dated: October 25, 2000
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EXHIBIT INDEX
Exhibit No. Description of Exhibit
99 Condensed Statement of Consolidated Income
for the three months ended September 30, 2000
