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: November 23, 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. California Public Utilities Commission Proceedings
1. Electric Industry Restructuring
As previously disclosed, in April 1994, the California Public
Utilities Commission (CPUC) issued an order instituting a
rulemaking and an investigation (OIR/OII) on electric industry
restructuring. The proposal, which is subject to comment and
modification, involves two major changes in electric industry
regulation. The first would move electric utilities from
traditional ratemaking to performance-based ratemaking. The second
would unbundle electric services and provide electric utility
retail customers the option to choose from a range of electric
generation providers, including utilities ("direct access").
On November 18, 1994, the Company filed testimony with the CPUC on
uneconomic assets and obligations which would result from the
CPUC's proposed electric industry restructuring. The testimony was
filed in compliance with an order issued by the CPUC in October
1994. In that order, the CPUC also set hearings for December 14
through December 22, 1994 to obtain information on the nature and
magnitude of utility assets and obligations which potentially may
be rendered "above-market" by the transition to market-based
pricing for generation under a direct access framework. The CPUC
has proposed that such stranded costs of utility generating assets
be recovered through a "competition transition charge" (CTC).
The Company's testimony, among other things, identifies and defines
the cost elements which must be included in the CTC, describes the
method used to calculate those costs, provides preliminary
estimates of the transition costs and discusses options for
allocating and recovering transition costs.
The Company defines the CTC as that portion of the Company's
generation-related assets and obligations which would not be
recovered if rates for power were set at competitive market prices.
The Company identified the following categories of CTC: (i)
Company-owned generation assets and non-qualifying facility (QF)
obligations; (ii) QF power purchase obligations, and (iii)
generation-related regulatory assets. As defined by the Company,
the CTC does not include the costs of existing social, energy
efficiency and environmental programs or the costs of
decommissioning existing fossil, nuclear and geothermal generation
facilities. These costs, which reflect ongoing public policy
commitments, will continue beyond the transition period and should
be recovered through a separate charge applicable to all consumers
of power.
The Company's testimony describes each of the three elements of the
CTC, and provides annual estimates of each over various
amortization periods. See the table set forth below. The ranges
in the table illustrate the high degree of uncertainty in
forecasting the CTC over the long term due to uncertainty in future
market prices. The portion of the CTC related to Company-owned
generation assets and long-term non-QF power purchase commitments
which were entered into in lieu of direct investment in Company-
owned facilities was determined by comparing the estimated future
revenue requirement of the portfolio with the revenue generated
based upon the range of assumed market prices (a range of 4 cents
per kilowatthour plus or minus 20 percent for baseload generation).
The estimated future revenue requirement related to the Diablo
Canyon Nuclear Power Plant was determined assuming the prices in
the Diablo Canyon Rate Case Settlement. The CTC estimate for
above-market QF power purchase obligations was derived by comparing
the estimated future revenue requirement associated with the
Company's agreements with QF power suppliers with the revenue
generated based upon the range of assumed market prices.
Regulatory assets represent the deferred recovery component of
prudent utility obligations and expenditures incurred in the past
that are scheduled for recovery through rates in the future. The
CTC estimates provided by the Company include the portion of the
regulatory assets which are attributable to the Company's electric
generation operations.
<TABLE>
PRELIMINARY COMPETITION TRANSITION CHARGE ANNUAL ESTIMATES<F1>
USING AMORTIZATION PERIODS FROM ASSIGNED COMMISSIONERS' RULING
<CAPTION>
_____________________________________________________________________________
Levelized Levelized Levelized Levelized
Recovery Recovery Recovery Recovery Over
Line Over 6 Years Over 9 Years Over 12 Years Remaining Life
No. Category of CTC ($ billion) ($ billion) ($ billion) ($ billion)
- ------------------------------------------------------------------------------------------------------
(A) (B) (C) (D)
------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1 Utility-Owned
Generation Assets and
Non-QF Obligations<F2> 0.1 to 2.8 0.1 to 2.1 0.1 to 1.8<F3> 0.1 to 1.4
2 QF Power Purchase
Obligations<F2> 0.45 to 0.89 0.34 to 0.67 0.28 to 0.56 0.20 to 0.39
Regulatory Assets:
3 Unrecovered ECAC
Balance <F4>
4 Other Generation-
Related Regulatory
Assets 0.15 0.11 0.09 0.07
- -------------------------
<FN>
<F1>
* The calculations presented in the filing are based on numerous assumptions, variables and estimates
of future prices, energy supplies and economic trends. The range of transition costs shown should
be viewed only as preliminary estimates.
<F2>
** Range based on different assumptions around market price.
<F3>
*** Under the Company's June 1994 proposal for a 12-year phase-in of direct access, the Company would
not seek CTC recovery of Company-owned generation and non-QF obligations.
<F4>
**** Balance expected to net to zero within this recovery period.
</FN>
</TABLE>
In its testimony, the Company referred to its June 1994 proposal
for recovery of CTC which blended the need for assured recovery of
above-market assets and obligations with a reasonable timetable for
achieving the transition to customer choice through direct access.
Under the Company's proposal to phase in direct access over 12
years, the Company would not seek CTC recovery of Company-owned
generation and non-QF obligations, and the Company would bear the
risk of recovery under existing ratemaking structures of that
portion of its generation-related assets and non-QF obligations
allocated to direct-access eligible customers. If the CPUC adopts
a shorter transition period for direct access, the Company
indicates that it would seek recovery of its above-market
generating asset portfolio as part of the CTC.
Under the Company's proposal, the CTC would be updated each year to
incorporate the most recent forecast of the market price for the
next year and any undercollections or overcollections of the CTC in
the previous year.
With regard to collecting the CTC, the Company asserts that the CTC
should be unbundled from utility transmission and generation
services as a separate surcharge, and should be collected in such
a manner that it is assessed to all customers interconnected to the
utility system. The Company proposes that the CTC be collected
through a separate line item on customers' bills that would
effectively be a customer interconnection charge, payable as a pre-
condition for continued interconnection to the utility's local
transmission and distribution facilities. The Company notes that
it may also be necessary to assess exit charges to prevent
customers from avoiding the CTC through complete
distribution/transmission bypass.
2. Restructuring of Gas Supply Arrangements - Recovery of
Interstate Transportation Demand Charges
Pursuant to Federal Energy Regulatory Commission (FERC) rules on
capacity relinquishment and release and the CPUC's capacity
brokering program, the Company makes available for brokering all
its interstate pipeline capacity not needed for core or core
subscription service. The Company began brokering its capacity on
the El Paso Natural Gas Company (El Paso) and Pacific Gas
Transmission Company (PGT) systems effective August 1, 1993 and
November 1, 1993, respectively.
Interstate transportation service which cannot be marketed at the
full rates results in unrecovered demand charges. Under its
brokering rules, the CPUC has authorized the use of an Interstate
Transition Cost Surcharge (ITCS) balancing account for unrecovered
demand charges associated with interstate pipeline obligations in
existence at the time the decision creating the ITCS was issued in
November 1991. To the extent the Company is unable to broker its
firm interstate capacity above core and core subscription
reservations at the full as-billed rate, or to broker such capacity
at all, the Company has been authorized to accumulate unrecovered
demand charges for firm transportation service from El Paso and PGT
in the ITCS account for later review and allocation among customer
classes. The firm transportation demand charges associated with
the Company's total firm capacity on El Paso and PGT are
approximately $130 million per year and $50 million per year,
respectively. The firm transportation agreements with El Paso and
PGT run through December 31, 1997 and October 31, 2005,
respectively.
On June 27, 1994, the Company filed an application seeking recovery
of $60.7 million, which represents the revenue requirement for the
estimated amount accrued in the ITCS account for the period August
1, 1993, through August 31, 1994. The Company's application sought
to have the $60.7 million recovered in non-core rates over a 12-
month period beginning September 1, 1994.
On November 9, 1994, the CPUC issued a decision in this proceeding
indicating that it did not have a sufficient record to resolve
contested issues regarding the total amount of the Company's
stranded costs of interstate pipeline capacity to allocate to
noncore customers. However, citing the fact that legitimate
stranded costs continue to accrue at a substantial rate, the
decision authorizes the Company to increase rates to all noncore
customers on December 1, 1994 through a rate designed to collect
$30 million of the requested amount on an interim basis, subject to
refund should ITCS costs prove to have been caused by improper acts
of the Company. The CPUC also set the matter for hearing at the
earliest practicable date to consider protests filed by El Paso.
El Paso contends that the Company is inducing customers from the El
Paso pipeline system to the Company's Expansion Project by
discounting rates on the Expansion Project and recouping those
discounts through the ITCS. The Company expects to seek recovery
of the balance of the ITCS amounts originally sought, either in the
hearing on this matter or in the Company's pending Biennial Cost
Allocation Proceeding.
3. Energy Cost Adjustment Clause
On November 21, 1994, the assigned Administrative Law Judge (ALJ)
issued a proposed decision in the Company's Energy Cost Adjustment
Clause (ECAC) proceeding which, if adopted by the CPUC, would adopt
a forecast of the Company's electric operations and costs for 1995.
The proposed decision adopts virtually every one of the Company's
proposals, both in the forecast of electric operations, and in the
implementation of a continuation of the Company's electric rate
freeze and associated deferral of collection of an undercollection
in the ECAC balancing account.
The proposed decision adopts all of the Company's proposals to
continue the electric rate freeze currently in effect, including a
$157 million ECAC increase to be offset by an attrition base rate
decrease, an early refund of $83 million in Customer Energy
Efficiency (CEE) program dollars collected from ratepayers but not
spent in 1993 and 1994, and deferral of collection of approximately
$470 million of ECAC costs forecasted to be undercollected as of
December 31, 1995. In granting the deferral, the proposed decision
would continue imposition of the three conditions placed on the
first deferral in last year's proceeding: (i) reinstatement of the
Annual Energy Rate (AER) mechanism, which places shareholders at
risk for nine percent of any deviations from forecasted operations,
(ii) no interest on the estimated revenue requirement deferral, and
(iii) written notification to all parties if the Company forecasts
that rates would need to rise an additional five percent to
amortize the undercollection.
The proposed decision agreed with the Company that the forgoing of
interest on the deferral amount was limited to the adopted deferral
amount and not to undercollections resulting from forecast error.
The proposed decision would also make it clear that the deferral
would not be considered a transition cost in any restructuring of
the electric industry, but could be separately collected from the
customers receiving electric service during the period in which the
deferred amounts were incurred. Finally, the proposed decision
notes that the deferred amount should be amortized before any
system-wide rate reductions are proposed or adopted.
A final CPUC decision is expected on December 21, 1994.
4. 1995 Cost of Capital Proceeding
On November 22, 1994, the CPUC announced its decision in the
Company's 1995 cost of capital proceeding authorizing a return on
common equity of 12.10%. This represents an increase from the
11.00% return on common equity allowed in 1994. The higher return
on common equity is intended to recognize increased interest rates
as well as increased risks associated with the CPUC's rulemaking
and investigation on electric industry restructuring in California.
The decision authorizes a utility capital structure of 48.00%
common equity, 5.50% preferred stock and 46.50% long-term debt,
which represents an increase from 47.50% in the current equity
component of the Company's capital structure. When combined with
the authorized costs of debt and preferred stock, the 12.10% return
on equity results in an overall return on rate base of 9.79% for
1995, compared with the 9.21% authorized for 1994.
The decision will increase revenue requirements by approximately
$104 million for electric rates and $33 million for gas rates,
effective January 1, 1995. However, consistent with the Company's
current electric rate freeze, the electric revenue increase
authorized in this proceeding would be offset by a decrease in base
revenues, such that electric rates would not increase through the
end of 1995.
B. PGT/PG&E Pipeline Expansion Project - Other Competitive
Interstate Pipeline Projects
As previously disclosed, in March 1993, Mojave Pipeline Company
(Mojave) filed a request seeking FERC authorization for
construction of a 475 million cubic feet per day (MMcf/d)
transportation-only pipeline expansion of its interstate natural
gas pipeline. Mojave indicated that it intends to place the
proposed expansion into service by January 1, 1996. The expansion
would extend Mojave's system from its current terminus in
Bakersfield, California, through California's Central Valley to
Sacramento and the San Francisco Bay Area. Mojave's filing
indicated that 433 MMcf/d of the firm service capacity provided by
the proposed expansion would be provided to customers located in
the Company's service territory, with approximately 257 MMcf/d of
that amount to be used to provide gas service that currently is not
provided by the Company. The remaining 176 MMcf/d represents
service to customers currently served by the Company.
In 1993 and the first half of 1994, the Company made various
filings with the FERC challenging the FERC's jurisdiction over
Mojave's application and opposing the application on substantive
grounds. In these filings, the Company indicated that Mojave's
proposed expansion would bypass the Company's existing gas network,
taking business from the Company and requiring the Company to
spread costs over a smaller customer base. The Company also
requested in its filings that the FERC hold an evidentiary hearing
to review the merits of Mojave's proposal and to establish a
mechanism to reimburse the Company for costs arising from bypass
associated with Mojave's proposed expansion.
In July 1994, the Company made a filing with the FERC indicating
that the lost revenues resulting from a bypass by the Mojave
expansion were estimated to be between $204 million and $223
million over a 15-year period, depending upon which of the four
alternate Mojave routes was assumed to be certificated. The
Company also requested that the FERC relieve the Company of up to
$86 million in charges for El Paso capacity that the Company
reserved to meet the needs of the Mojave-targeted customers.
On November 9, 1994, the FERC voted unanimously to approve, with
conditions, Mojave's expansion application. On November 18, 1994,
the FERC issued its Preliminary Determination on Nonenvironmental
Issues, granting Mojave a permit to construct, subject to further
environmental review. The FERC order imposes a condition that
construction cannot commence until Mojave has binding contracts for
100 percent of the firm pipeline capacity, and instructs Mojave to
submit a filing prior to construction showing the configuration of
the pipeline system which it intends to construct, as supported by
its binding service contracts. The order states that Mojave
currently has firm contracts for approximately 200,000 MMBtu per
day, which is less than half the project's proposed capacity.
With respect to the Company's request for compensation, the FERC
order rejects the Company's claim that the Mojave expansion will
result in lost net revenues of between $204 million and $223
million. Instead, the FERC adopts a figure of approximately $5
million per year for 15 years, and finds that this level of costs
is not sufficiently large to justify rejection of Mojave's
application. It is not clear whether the FERC intends to impose a
condition that Mojave compensate the Company for such revenue
losses.
With respect to the Company's request for contract demand relief,
the FERC order leaves open the possibility that contract demand
relief will be granted, but defers ruling on the issue at this
time. The order directs the Company, Mojave and El Paso to provide
the FERC with additional information explaining whether a
connection exists between the Company's obligation to purchase
service from El Paso and Mojave's service to the bypassing end-
users, and specifying what type and volume of load will be lost by
the Company as a direct result of bypass by Mojave.
C. Diablo Canyon Nuclear Power Plant
1. Diablo Canyon Rate Case Settlement
As previously disclosed, in August 1994, the CPUC's Division of
Ratepayer Advocates (DRA) filed a petition seeking to modify the
CPUC's 1993 order refusing to reconsider the Diablo Canyon Rate
Case Settlement (Diablo Settlement). The DRA requested that the
CPUC modify its earlier decision for the purpose of reopening the
Diablo Settlement to consider modification of the payment
methodology included therein. In addition, the DRA recommended
that the price paid for electricity generated by the Diablo Canyon
Nuclear Power Plant (Diablo Canyon) be frozen at the 1994 price
level. On October 19, 1994, an ALJ of the CPUC issued a ruling on
the DRA's petition, scheduling a hearing for December 20, 1994 on
the DRA's petition, and ordering the parties to submit affidavits
and exhibits in support of or opposed to the DRA's motion prior to
the hearing.
On November 17, 1994, the ALJ issued an order granting a motion by
the Company to delay the hearing pending discussions among the
parties which might resolve the issues raised by the DRA's petition
without further litigation. The Company's motion was supported by
the DRA, the California Attorney General and several other parties
representing energy consumers. The Company has commenced
discussions with the DRA and the parties representing energy
consumers to explore possible changes in the pricing mechanism
established by the Diablo Settlement.
The order sets a new hearing date of January 13, 1995, a deadline
of December 12, 1994 for the filing of affidavits and exhibits by
the DRA and the parties supporting the DRA's position, and a
deadline of January 3, 1995 for the filing of affidavits and
exhibits by the Company and the parties supporting the Company's
position.
2. Diablo Canyon License Amendment
As previously disclosed, in July 1992, the Company filed a license
amendment request with the Nuclear Regulatory Commission (NRC) to
change the operating license expiration dates for both units at
Diablo Canyon. Diablo Canyon Units 1 and 2 were originally
licensed to operate for 40 years commencing on the date the
construction permit for the respective unit was issued, which
occurred in April 1968 and December 1970, respectively. In 1982,
the NRC determined that the 40-year term of operation for nuclear
power plants may instead begin upon issuance of the first operating
license. The Company's request sought to utilize that policy
change and to extend the operating license expiration date for
Units 1 and 2 to September 2021 and April 2025, respectively.
On November 4, 1994, the NRC's Atomic Safety and Licensing Board
issued its decision approving the Company's request for a full 40-
year operating license for Diablo Canyon.
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
GORDON R. SMITH
By ________________________________
GORDON R. SMITH
Vice President and
Chief Financial Officer
Dated: November 23, 1994
