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: May 26, 1995
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
On May 24, 1995, the California Public Utilities Commission
(CPUC) released two proposed policy decisions to restructure the
California electric utility industry. Three commissioners
indicated a preference for a policy decision which would require
the establishment by the three major California electric
utilities, including the Company, of a wholesale pool for power,
with other participants in California and elsewhere invited to
join the pool. This proposal, which would go into effect in 1997,
contemplates a possible transition to direct access beginning in
1999 if certain implementation issues are resolved. One
commissioner offered an alternative policy decision which
proposes direct access whereby all consumers could enter directly
into individual agreements for the purchase of power from power
producers commencing in 1998.
MANDATORY POOL PROPOSAL
Under the policy decision supported by the majority, the
wholesale pool would implement transparent pricing on a real time
basis (hourly or half-hourly) and publish market prices for
electricity. Utilities would be required to purchase power from
the pool and bid into the pool their remaining generation output.
All sellers except existing wholesale and Qualifying Facility
(QF) contracts, and nuclear and hydroelectric plant output would
be scheduled according to competitive bidding. Nuclear,
hydroelectric (hydro) and QF resources would be scheduled on a
priority basis.
Customers would be given the choice between real time pricing of
generation or pricing which averages the cost of electricity by
monthly consumption. Customers could also choose to fix their
energy costs through "contracts for differences." Real time price
meters would be phased in for all customers, with all customers
receiving meters by 2003. Customers would be individually
responsible for the cost of their meter.
The majority proposal notes that physical bilateral contracts may
be allowable in the future if certain conditions are met. These
include a mechanism for recovering transition costs, resolution
of jurisdictional uncertainties, determination of the technical
feasibility of bilateral contracts and resolution of horizontal
market power issues.
Disaggregation of Generation, Transmission, and Distribution
The pool proposal would require the disaggregation of generation,
transmission and distribution functions. Participants in the
pool would transfer control, but not ownership, of transmission
assets to an independent system operator, who would be
responsible for transmission scheduling and economic dispatch of
generation.
While finding that market power over generation must be
addressed, the majority proposal stops short of mandating
divestiture. However, parties are asked to comment on the
appropriate method of addressing utility market power over
generation, such as corporate separation, divestiture into
smaller generating firms, and potential remedies for abuses.
Transition Costs
The majority proposal would leave intact settlements related to
nuclear power plants (including the purchase power obligation
associated with the Company's Diablo Canyon nuclear power plant
(Diablo Canyon) rate case settlement) and utility contracts with
existing QFs.
Investor owned utilities would retain ownership of their existing
nuclear and hydro facilities, due to the difficulty of
transferring the ownership and operation of such facilities to
another party given the extensive licenses and permits needed
from various federal and state authorities. The CPUC hopes that
the average bundled rate of nuclear and hydro facilities would be
competitive with the prices expected to result from the pool,
thereby minimizing or eliminating the need for further
"competitive transition charge" (CTC) recovery from these
resources.
In light of this proposal, the CPUC asks for comment on whether
there is any need for any CTC recovery related to the Company's
purchase power obligation from Diablo Canyon, and, if so, what is
the potential magnitude. The CPUC notes that the Company has
offered to forego CTC recovery if direct access is not completely
phased in until 2008, and, noting that Diablo Canyon would be
bundled with hydro, therefore asks for comment on whether there
is need for any further recovery for Diablo Canyon CTC after
2004. Based on the current pricing of the Company's hydro
facilities and Diablo Canyon, the Company expects that there may
be a need for some CTC recovery from these facilities after 2004.
The majority proposal notes that other utility generating assets
should also be able to compete without CTC recovery, or else are
likely to be spun-off or divested. Nonetheless, some CTC recovery
would still be provided for non-nuclear, non-hydro plants which a
utility retained. The CTC for these plants is defined as the
difference between book and market value. Market value for
retained plants would be determined administratively using a
combination of a forecast of market prices for power with an
annual true up to pool prices. For these retained plants, the
rate of return on rate base would be limited by a floor and
ceiling of 150 basis points below and above the utility's
allowable overall return on rate base; e.g., if the utility's
authorized return is 10%, it would not receive a CTC on these
power plants unless its return on the power plants was less than
8.5%, and if the return exceeded 11.5%, the excess revenue would
be credited against the CTC account.
If a utility divests itself of its generating assets, the CTC
would be calculated by netting the total price received with the
total book value for the set of plants divested.
All existing QF contracts would continue to be honored by the
remaining electric distribution utility. However, the QF
contract costs would be passed along to customers by imputing
only the pool price as the price for QF power, with the remaining
portion of the QF contract price collected as part of CTC.
As an incentive for QF buyouts, the utility would be allowed to
keep 20% of any savings from renegotiated QF contract capacity
payments. In addition, the CPUC eventually intends to revise the
"avoided cost" calculation for QF energy payments in a manner
based on the pool price. Finally, the CPUC proposes to allocate
50% of future benefits associated with declining QF contract
expenses to finance acceleration of CTC recovery for uneconomic
QF contracts.
The majority proposal indicates that regulatory assets which are
specifically attributable to utility generation should get full
CTC protection. The CPUC asks for comments on which specific
regulatory assets should be allowed as transition costs.
The time period for collection of CTC is not specified in the
majority proposal, but would be consistent with the current level
of rates, while also allowing ratepayers the opportunity to reap
the benefits of lower generation costs from the pool.
Performance Based Ratemaking
In its proposal, the majority reaffirms its commitment to
performance based ratemaking (PBR) and proposes to apply PBR
mechanisms to utility generation and distribution services. The
CPUC indicates that it will consider each of the pending PBR
applications filed by the utilities individually and design a
mechanism that is tailored to fit each utility's needs and
particular circumstances.
Resource Planning
Under the majority proposal, the CPUC proposes to relieve
utilities from the obligation of planning or constructing new
generating resources. With respect to transmission planning, the
proposal notes the CPUC's intent that the pool offer for
consideration by the Federal Energy Regulatory Commission (FERC)
an (unspecified) transmission pricing methodology which embodies
comparable transmission prices and encourages efficient
transmission investments through some type of sensitivity to
transmission congestion.
CEQA
The CPUC had in an earlier order recognized the possible
applicability of the California Environmental Quality Act (CEQA)
to restructuring. The current proposal seeks comment on whether
the proposed restructuring would constitute a project requiring
environmental review. Applying CEQA could have consequences for
the timing of any final order.
ALTERNATIVE DIRECT ACCESS PROPOSAL
The alternative proposed policy decision offered by one
commissioner would provide for vertically integrated investor-
owned utilities to divest themselves, through either sale of
assets or spin-off to shareholders, of generation facilities.
This policy approach would leave the residual utility owning only
transmission and distribution facilities (Electric Distribution
Company, or EDC). The CPUC would have to preapprove all
divestiture actions by utilities.
The costs and services provided by EDC would continue to be
regulated by the CPUC under a PBR approach. Customers could elect
to remain with the EDC, which would have the obligation to
provide them bundled service, or become direct access customers,
buying their power elsewhere, with the EDC obligated to wheel and
distribute power to them.
The proposal calls for the establishment of a neutral operating
company (OPCO) to dispatch transactions and ensure reliability of
the grid.
Transition costs (discussed in more detail below) would be
calculated and a CTC would be levied as a fixed monthly charge on
all customers, utility or direct access (i.e. regardless of their
source of supply). The CTC would be recovered over a period of
time to ensure that rates do not rise above current levels.
Direct access would not be permitted until the CPUC had completed
work on the calculation and recovery of stranded costs and
unbundling of utility services. Direct access would be available
to all customers at once -- no phase-in is proposed. The
proposal seeks to begin allowing consumers to choose from among
competing generation service providers starting in 1998.
Transition Costs
Three types of transition costs are identified in the alternative
proposal: utility generation assets, QF contracts and regulatory
balancing accounts.
Utility generating assets: CTC would be 90% of the difference
between aggregate book value and aggregate sales price (or stock
price in the event of a spin off). Diablo Canyon would be sold
or spun off, but the EDC would retain the obligation to purchase
Diablo Canyon power at settlement prices through January, 2008,
along with the QF contracts. After January, 2008, Diablo Canyon
would compete on price. The CTC for Diablo Canyon would be
computed in the same manner as for QF contracts, but Diablo
Canyon would be exempt from the 90/10 split applicable to other
utility generating assets if the revised Diablo Canyon settlement
prices approved by the CPUC on May 24, 1995 represent a rate
reduction "commensurate" with the 90/10 split.
QF contracts: The EDC would receive full recovery of all QF
costs. It could charge its remaining customers the market price
for QF power; the uneconomic portion, i.e. the difference between
contract and market price, would be part of the CTC. The
alternative proposal suggests that utilities be given an
incentive to renegotiate QF contracts by allowing shareholders to
retain 50% of any demonstrable savings.
Outstanding balances in regulatory accounts: Full recovery is
proposed for outstanding balances other than nuclear
decommissioning costs, subject to CPUC approval of specific
accounts in the implementation phase. For nuclear
decommissioning costs, two options are proposed: ultimate sale
of the plants with the new owner taking responsibility for
decommissioning or including in CTC the continued trust fund
requirements.
Obligation to serve
EDCs would be obligated to procure electric supplies for those
customers who decline direct access and are provided bundled
service. EDCs would also be obligated to provide unbundled
transmission and distribution services to direct access
customers. Transmission and distribution services would remain a
monopoly and be subject to PBR.
For direct access customers choosing to return, the EDC would
have the obligation to procure power for such customers at the
true cost of procurement. For non-residential customers, this
would be pursuant to terms and conditions negotiated with the
utility. Returning residential customers would be able to return
to the same services and conditions only upon three years'
notice. In the interim, the customer would be subject to a
"return tariff" based on market prices.
Role of OPCO
OPCO -- the independent grid operator -- would have the role of
ensuring open access to all participants; maintaining system
coordination and reliability; and settling imbalances that might
occur on the system due to changes in demand or delivery. Market
prices determined through bilateral negotiation would determine
the dispatch of generation assets as opposed to a centralized
bidding system.
PROCEDURAL SCHEDULE
Comments on both proposed policy decisions, including responses
to specific questions posed by the CPUC, will be taken during the
next three months. The CPUC indicated that it will issue, no
sooner then August 23, 1995, its final policy decision with a
schedule of steps for implementation. The CPUC indicated that it
will work with the California State Legislature, the Governor,
other western jurisdictions and the FERC to facilitate
restructuring of the California electric industry. It is
anticipated that the Legislature will conduct hearings on the
CPUC's proposals this summer.
2. Diablo Canyon Rate Case Settlement
On May 24, 1995, the CPUC issued its decision approving an
agreement providing for a modification to the pricing provisions
of the Diablo Canyon rate case settlement (Diablo Settlement).
The agreement was executed in December 1994 by the Company, the
CPUC's Division of Ratepayer Advocates (DRA), the California
Attorney General and several other parties representing energy
consumers and submitted to the CPUC for approval. The CPUC
decision also denies a request by a consumer advocacy group for
public hearings on the pricing modification.
Under the modification approved in the CPUC's decision, the price
for power produced by Diablo Canyon is reduced from the level set
in the Diablo Settlement as originally adopted in 1988; all other
terms and conditions of the Diablo Settlement remain unchanged.
The new prices are shown in the table below. Based on Diablo
Canyon's current operating performance, the modification will
result in approximately $2.1 billion less revenue over the next
five years, compared to the original pricing provisions of the
Diablo Settlement.
Diablo Canyon Price (cents) per kilowatt-hour
1995 1996 1997 1998 1999
Original Settlement Agreement Price* 12.15 12.42 12.70 12.98
13.28
Modified Price 11.00 10.50 10.00 9.50 9.00
______________
* Assumes 3.5% inflation
After December 31, 1999, the escalating portion of the Diablo
Canyon price will increase using the same formula specified in
the Diablo Settlement. The modification provides the Company
with the right to reduce the price below the amount specified if
it so chooses.
The CPUC decision approving the modification adopts the parties'
proposal that the difference between the Company's revenue
requirement under the original Diablo Settlement prices and the
proposed prices be applied to the Company's energy cost balancing
account until the undercollection in that account as of December
31, 1995 is fully amortized.
3. Biennial Cost Allocation Proceeding
As previously disclosed, in April 1995 the Company updated its
application in its Biennial Cost Allocation Proceeding (BCAP),
the major rate proceeding for the Company's natural gas service.
The Company's updated application requested an increase in gas
revenues from revenues at current rates of approximately $25
million annually, for the two-year period beginning January 1,
1996. At a prehearing conference on May 24, 1995, the assigned
administrative law judge rejected the Company's update to its
application. However, much of the information in that update
which reduced the Company's request, as compared to the request
included in its original application, was incorporated into the
report filed by the DRA, which is described below.
The DRA filed its report on the Company's BCAP application on May
12, 1995. The DRA recommended a decrease of approximately $78
million annually in gas revenues from revenues at current rates,
which represents a $103 million difference from the annual gas
revenue change requested by the Company in its update. The
reduction results primarily from (1) recovery of only 50% of the
Company's estimated and forecasted costs associated with Canadian
pipeline transportation charges; (2) interim recovery of 50% of
accumulated and forecasted amounts in the Interstate Transition
Cost Surcharge (ITCS) balancing account, which amounts represent
demand charges for interstate gas transportation capacity held by
the Company which are not currently fully recovered under the
operation of the CPUC's capacity brokering rules, pending a final
decision in the ongoing ITCS rate proceeding; and (3)
amortization of amounts accumulated in a gas cost balancing
account as of an earlier date than the Company used in
calculating its BCAP request.
In addition, the DRA recommended that the Company not be allowed
to recover any of the amounts accrued in the Backbone Credit
Memorandum Account (BCMA), which was established in connection
with interim rates for the Company's Pipeline Expansion Project,
otherwise known as Line 401. Certain customers using Line 401
are credited for amounts associated with transmission charges on
the Company's pre-Expansion, or existing, system that would
otherwise be included in Line 401 rates. The Company had sought
recovery of the revenue shortfalls attributable to these credits,
which totaled $12 million, as part of its BCAP application. The
DRA recommended that this amount should be disallowed because the
Company erred in not reducing the amount accrued in the BCMA to
take account of the fact that some of the existing system load
that was lost when customers shifted to Line 401 had been taken
up by new customers. The DRA argued that this results in the
Company, in effect, collecting existing system transmission
charges twice, first from new customers and second from recovery
of BCMA amounts.
In its report, the DRA also recommends that there be no rate
recovery of any revenue shortfalls resulting from certain long-
term gas transportation contracts which provide discounted rates
for certain industrial customers. These contracts were approved
by the CPUC under the Expedited Application Docket (EAD)
procedure. The Company is currently precluded from recovering in
rates 25% of the revenue shortfalls resulting from discounts
given in EAD contracts until the CPUC makes a further
determination as to rate recovery of such amounts in the pending
BCAP proceeding.
The DRA is the consumer advocacy branch of the CPUC and the DRA's
recommendations do not constitute a CPUC decision. The CPUC can
accept all, part or none of the DRA's recommendations.
4. Experimental Procurement Service for Customer-
Identified Electric Supply
As previously disclosed, in February 1995, the Company requested
CPUC approval to implement an experimental "buy-sell" program for
electric supply, which the Company believed could be determined
to be subject to the CPUC's exclusive jurisdiction. Under the
program, California utilities would offer certain retail
customers the option of having the utility purchase power on the
customer's behalf from third party competitive suppliers at
prices individually negotiated by the participating customer.
On May 17, 1995, the Company withdrew its request for CPUC
approval of the proposed buy-sell program, citing the recently
issued FERC Notice of Proposed Rulemaking which indicated that
the Company's buy-sell proposal involved unbundled transmission
service which was subject to FERC jurisdiction. The Company
indicated that it had concluded that, at this time, the proposed
buy-sell program could not achieve the purpose for which it was
developed, which was to conduct an experiment in customer choice
without the need to address the complex issues surrounding direct
access.
B. Common Stock Repurchase Program
In July 1993, the Company's Board of Directors (Board) authorized
the Company to repurchase up to $1 billion of common stock on the
open market or in negotiated transactions under its common stock
repurchase program. As of March 31, 1995, the Company had
repurchased approximately $540 million of stock under that
authorization. In May 1995, the Board authorized the Company to
purchase up to an additional $1 billion of common stock under its
repurchase program through June 1998. This program is funded by
internally generated funds. Shares will be repurchased to manage
the overall balance of common stock in the Company's capital
structure.
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: May 26, 1995
