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 11, 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. Performance Incentive Plan - Year-to-Date Financial Results
The Performance Incentive Plan (Plan) is an annual incentive
compensation plan applicable to all regular non-bargaining unit
employees of the Company and designated subsidiaries. The Plan
provides for awards based on (1) the Company's success in meeting
overall corporate financial performance objectives, based on
earnings per share for the Company; and (2) the performance of
the employee's organizational unit in meeting its individual
objectives. The corporate and organizational objectives include
quality and reliability of service to customers, financial
performance, cost control and operational efficiency.
Under the Plan, the Nominating and Compensation Committee of the
Board (Committee) makes the final determination of awards based
upon achievement of the Plan objectives. The Committee has the
discretion to modify or eliminate awards.
The performance measurement target for the 1994 Plan year was
disclosed in a Report on Form 8-K dated January 10, 1994, and
was based upon the corporate capital and operating budgets
prepared for 1994. The Company's overall earnings per share is
comprised of earnings per share for the Company's three types of
operations: utility, Diablo Canyon nuclear power plant (Diablo
Canyon) and nonregulated through PG&E Enterprises, a wholly owned
subsidiary.
The 1994 budgeted earnings per share for the utility were derived
from, among other things, (i) budgeted revenues as authorized by
the CPUC for 1994 which includes the impact of the Company's
economic stimulus rate, the electric rate freeze and the
corporate reorganization and workforce reduction program
announced in early 1993, (ii) the Company's capital budget for
1994 of approximately $1.4 billion for utility operations and
(iii) budgeted operating expenses for utility operations that are
approximately 5% less then budgeted for 1993. The utility
budgeted earnings per share assumes contribution to earnings of
$.10 per share from Pacific Gas Transmission Company, a wholly
owned subsidiary of the Company, of which $.09 per share relates
to the interstate portion of the PGT-PG&E pipeline expansion
project. The budgeted earnings per share for utility assumes no
earnings for the California portion of the expansion project. As
previously disclosed, shippers on the California portion of the
PGT-PG&E pipeline expansion project have only executed long-term
firm transportation contracts for approximately 40% of the
intrastate capacity, and the Company continues negotiations for
the remaining capacity.
The budgeted earnings per share for Diablo Canyon were derived
from, among other things, (i) an operating capacity factor
(excluding refueling outages) of 91%, (ii) an overall annual
capacity factor of 75.3% and (iii) one 64-day refueling outage at
Unit 1 and one 62-day refueling outage at Unit 2 during 1994.
Budgeted operating expenses for 1994 relating to Diablo Canyon
are approximately 13% more than budgeted for 1993. Budgeted
capital expenditures for Diablo Canyon are approximately $105
million for 1994.
The budgeted earnings per share for the period ending December
31, 1994, assume 425 million shares of common stock outstanding.
The budgeted earnings per share amounts assume no significant
gain or loss on the sale of assets. Actual performance during
the year may differ materially from the budgeted amounts.
As previously reported, the Company discloses the year-to-date
financial performance of the Company relating to the three types
of operations: utility, Diablo Canyon and PG&E Enterprises. For
the one month ended January 31, 1994, selected financial
information is shown below:
(in thousands, except per share amounts)
One Month Ended January 31, 1994
=================================================================
Actual (1) Budget (2)
Operating Revenues: (unaudited)
Utility $ 696,127 $ 729,831
Diablo Canyon 140,511 (3) 126,234
PG&E Enterprises 574 404
----------- -----------
Total Consolidated $ 837,212 $ 856,469
=========== ===========
Net Income (Loss):
Utility $ 69,409 $ 68,665
Diablo Canyon 35,956 (3) 24,441
PG&E Enterprises (1,307)(4) (825)
------------ ----------
Total Consolidated $ 104,058 $ 92,281
=========== ===========
Earnings Per Common
Share:
Utility $ 0.15 $ 0.15
Diablo Canyon 0.08 (3) 0.05
PG&E Enterprises 0.00 (4) 0.00
----------- -----------
Total Consolidated $ 0.23 $ 0.20
========== ===========
(1) In the opinion of management, the unaudited "actual"
financial information presented above reflects all adjustments to
date which are necessary to present a fair statement of operating
revenues, net income and earnings per common share for the
interim period. All material adjustments are of a normal
recurring nature. The actual results above are not necessarily
indicative of the results to be obtained in the full fiscal year.
This information should be read in conjunction with the 1993
Consolidated Financial Statements and Notes to Consolidated
Financial Statements contained in the Company's Report on Form 8-
K dated March 2, 1994.
(2) The budgeted amounts are performance targets and not
forecasts of actual performance that is expected or will be
realized by the Company. The budgeted amounts do not reflect the
resolution of various regulatory uncertainties or other
contingencies, including those disclosed in the Company's Notes
to Consolidated Financial Statements, which could affect the
Company's performance during the year.
(3) Diablo Canyon operated at an overall capacity factor of
99.4% compared to a budgeted overall capacity factor of 91.0% for
the one month ended January 31, 1994.
(4) In January 1994, the Company's board of directors approved a
final plan for the disposition in 1994 of PG&E Resources Company
(Resources), a wholly owned subsidiary of PG&E Enterprises, if
market conditions remain favorable. Resources' operations for
January 1994 resulted in a loss of $151,000, net of a $2,732,000
tax benefit. Resources is an oil and gas exploration company
headquartered in Dallas, Texas.
B. California Public Utilities Commission (CPUC) Proceedings -
1. Regulatory Reform Initiative
The Company has been engaged in discussions with the CPUC,
customers and other interested parties concerning various reforms
to the current regulatory approach to setting rates. On March 1,
1994, the Company filed an application with the CPUC requesting
it adopt the Company's proposed Regulatory Reform Initiative
(RRI) and approve 1995 electric and gas base revenue
requirements.
The RRI is, in part, a response to the report issued in February
1993 by the CPUC's Division of Strategic Planning on electric
industry restructuring. That report concluded that the current
regulatory approach is incompatible with the emerging industry
structure resulting from technological change, competitive
pressure and new market forces. The report indicated that the
existing cost-of-service ratemaking does not provide sufficient
incentives for efficient utility operations and
disproportionately favors additions to rate base as opposed to
energy efficiency or purchased power alternatives, and that the
number and complexity of proceedings result in significant
administrative costs and burdens which threaten the quality of
public participation in CPUC proceedings. Although the report
indicated the necessity for reform of the regulatory framework,
it did not ultimately recommend a specific strategy.
The Company's RRI has three components: (i) performance based
ratemaking (PBR) for determining base revenues; (ii)
establishment of a Large Electric Manufacturing Class (LEMC) of
customers; and (iii) use of market benchmarks to evaluate gas
procurement costs. A specific proposal regarding the third
component is not included in the Company's March 1, 1994 filing,
but is expected to be filed at a later date.
In its filing, the Company proposes a schedule calling for
technical workshops in April, public hearings beginning in June
and a final CPUC decision by the end of 1994. The Company has
requested that the RRI become effective on January 1, 1995.
PBR Proposal
Under the Company's PBR proposal, electric and natural gas base
revenues would be determined annually by formula rather than
through General Rate Cases, Attrition Rate Adjustments and Cost
of Capital proceedings. Base revenues are the revenues intended
to offset the Company's operation and maintenance expenses
(excluding costs for fuel or fuel-related items), depreciation
expense, income and other taxes, and to provide a return on
invested capital. Revenues to offset fuel and fuel-related costs
would still be determined in the Energy Cost Adjustment Clause
proceeding for electric operations and the Biennial Cost
Allocation Proceeding for gas operations.
The Company's proposed PBR mechanism would determine the base
revenues for a given calendar year by multiplying the base
revenues authorized for the prior calendar year by an index
consisting of inflation plus customer growth less a prescribed
productivity factor. Those revenues would also be adjusted up or
down depending on the Company's achievement relative to four
performance standards: Customer Energy Efficiency (CEE)
programs, Energy Bills (i.e., a comparison of the Company's
overall residential electric and gas bills relative to national
averages), Customer Satisfaction and Electric Service
Reliability. The positive or negative adjustments related to the
Company's performance in these four areas would be one-time
modifications to that year's base revenues as calculated under
the PBR index formula. The adjustments for CEE incentives would
be determined as they currently are under existing ratemaking
procedures. The maximum adjustments that the Company could earn
related to Energy Bills and Customer Satisfaction is $25 million
per year for each, and the maximum for Electric Service
Reliability is $19 million per year. Under PBR, the Company
could also apply for an adjustment to base revenues due to the
occurrence of certain extraordinary events outside the Company's
control, including events that would currently qualify for
ratemaking treatment through the existing Catastrophic Events
Memorandum Account.
The PBR proposal provides for the sharing between ratepayers and
shareholders of earnings above or below a target utility return
on equity (ROE) that would be computed annually. To the extent
actual ROE exceeds more than 200 basis points above or below the
target ROE, the difference would be shared equally with
ratepayers through a reduction or increase in the next year's
base revenue. If actual ROE was more than 500 basis points above
or below the target ROE, then the Company and the CPUC would each
have the option to initiate a proceeding to reexamine the PBR
formula.
The Company is proposing that base revenue indexing begin in
1995. However, the Company proposes to forgo any increase in the
electric base revenue for 1995 determined under the PBR
mechanism. Instead, 1995 electric base revenue would be held at
the 1994 level.
In its filing, the Company proposes that the RRI remain in place
indefinitely. The Company recommends that after five years the
CPUC review the PBR mechanism and make any necessary adjustments,
but not return to the use of traditional rate cases to set rates.
LEMC
As proposed by the Company, the LEMC would consist of the
Company's largest electric accounts (having an average hourly
electricity usage over a 12-month period of at least 2,000
kilowatts) engaged in manufacturing. Currently, approximately
120 accounts would qualify for inclusion in the LEMC.
LEMC customers would be removed from cost-of-service ratemaking.
Standard LEMC tariff rates would be determined every calendar
year by an index formula, similar to that used in the PBR
mechanism, which is intended to reflect inflation less a
productivity factor. In addition, several long-term tariff
options designed to respond to these customers' competitive
alternatives would be offered to the LEMC. The Company also
seeks authorization to negotiate and enter into customized
contracts with LEMC customers. In some cases, the customized
contracts would become effective without prior approval or
subsequent review by the CPUC of the contract terms.
Generally, the Company proposes to separate the costs allocated
to the LEMC and bear the risk of their recovery if sales to these
customers decline over time. The Company's shareholders would
bear the risk of LEMC fuel costs that increase faster than the
LEMC price index.
Accounting Impact
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, the Company defers
recognition of costs which would otherwise be expensed when
incurred because regulators have provided mechanisms that make it
probable that the costs will be included in future rates. If the
RRI is adopted, the mechanics of the rate setting process would
change. However, the Company anticipates that rates derived from
the RRI would remain based on cost-of-service, with the exception
of rates for the LEMC customers and rates established under
certain other regulatory mechanisms proposed to be discontinued
upon adoption of the RRI.
If the RRI is adopted as proposed, the Company anticipates that
it will write-off regulatory assets, including an estimated $65
million related to the LEMC customers and potentially additional
amounts which may be affected by the adoption of the RRI, the
aggregate amount of which could have a significant adverse impact
on the Company's financial position or results of operations.
The estimated amount related to the LEMC is based on the base
revenue allocation currently used in establishing rates; the
actual amount could vary depending on the allocation method
adopted by the CPUC.
The final determination of the accounting impact will be
dependent upon the form of the regulatory reform ultimately
adopted. In the event that specific recovery of costs through
rates becomes unlikely or uncertain, whether resulting from the
expanding effects of competition or specific regulatory actions
which force the Company away from cost-of-service ratemaking,
SFAS No. 71 would no longer apply. Discontinuation of SFAS 71
would cause the write-off of the applicable portion of regulatory
assets, including regulatory balancing accounts receivable and
those regulatory assets included in deferred charges, which could
have a significant adverse impact on the Company's financial
position or results of operations.
2. 1988-1990 Reasonableness Proceeding - Canadian Issues
As previously disclosed, on November 15, 1993, the assigned
Administrative Law Judge (ALJ) issued a proposed decision on the
Company's Canadian gas procurement activities during 1988 through
1990. The ALJ's proposed decision recommends a disallowance of
approximately $46 million of gas costs plus accrued interest
estimated at approximately $15 million as of September 30, 1993.
The CPUC's Division of Ratepayer Advocates (DRA), a consumer
advocacy branch of the CPUC staff, had previously recommended
that the Company refund $392 million based on its contention that
the Company should have purchased 50% of its Canadian supplies on
the spot market instead of almost relying totally on long-term
contracts. Based on its assessment of the matter, the Company
recorded a reserve of $61 million in 1993 for any disallowance
that may be ordered by the CPUC in the gas reasonableness
proceeding.
A final CPUC decision on the Company's Canadian gas procurement
activities for the 1988-1990 record period is on the agenda to be
considered at the CPUC's March 16, 1994 meeting. The agenda for
that meeting indicates that the CPUC is considering at least
three alternatives to the proposed decision. The Company
currently believes that it is reasonably likely that the CPUC's
final decision will order a disallowance above the $61 million
recommended by the ALJ's proposed decision, but within the range
of the ALJ's proposed decision and the $392 million recommended
by the DRA.
The DRA has also recommended disallowances in respect of the
Company's Canadian gas procurement activities for the 1991 and
1992 record periods of $105 million and $60 million,
respectively. Final decisions in those proceedings are expected
later in 1994.
3. 1988-1990 Reasonableness Proceeding - Non-Canadian
Issues
On March 9, 1994, the CPUC issued a final decision on the
Company's non-Canadian gas and electric operations activities
during 1988 through 1990. The final decision disallows recovery
of approximately $7.8 million in costs, primarily related to
costs that could have been avoided by increasing withdrawals from
storage to avoid gas curtailments in December 1990 for the
electric department's generation.
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
THOMAS C. LONG
By ________________________________
THOMAS C. LONG
Controller
Dated: March 11, 1994
