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: September 9, 1996
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. Electric Industry Restructuring Legislation
On August 31, 1996, the California State Legislature adopted
legislation, Assembly Bill (AB) 1890, which comprehensively
restructures the regulation of electric utilities in California. The
legislation is supported by Pacific Gas and Electric Company (PG&E)
and a coalition of customer, utility, business, environmental,
agricultural, labor, independent power producer, and local government
groups. The legislation now goes to the Governor, who will have
thirty days to sign or veto it. The legislation would be effective
upon enactment. The following are the major provisions of AB 1890:
Recovery of Uneconomic Costs:
The legislation authorizes utilities subject to the regulation of the
California Public Utilities Commission (CPUC) to recover the
uneconomic costs of their generation-related assets and obligations
(referred to in the legislation as "Competition Transition Costs").
These uneconomic costs (CTCs) would be recovered from all customers
(with certain exceptions) through a non-bypassable charge included as
part of rates over the period ending December 31, 2001, with the
possibility of extension beyond December 31, 2001 for certain CTCs,
such as employee-related transition costs (recoverable through
December 31, 2006) and costs resulting from implementation of direct
access, creation of a power exchange and independent operation of the
transmission system. As a prerequisite to any consumer obtaining
direct access services (see "Direct Access," below), the consumer must
agree to pay its applicable non-bypassable CTC charge, through the
rates or tariffs under which the consumer is obtaining service from
the utility, or by written confirmation if the consumer is not using
the utility's facilities for direct access. Until January 1, 2002,
electricity marketers must advise their direct access customers of
their obligation to execute a written confirmation of their obligation
to pay the applicable non-bypassable CTC charge.
Generation-related assets and obligations are defined to include those
costs and categories of costs consisting of generation facilities,
generation-related regulatory assets, nuclear settlements, and power
purchase contracts, including restructuring, renegotiations or
terminations thereof approved by the CPUC, that were being collected
in rates as of December 20, 1995, along with costs incurred after that
date for capital additions to such generating facilities that the CPUC
determines are reasonable and necessary to maintain the facilities
through December 31, 2001. Employee-related transition costs
associated with officers, senior supervisory employees, and
professional employees performing predominantly regulatory functions
are not recoverable.
CTCs associated with existing power purchase contracts, such as those
for purchases from Qualifying Facilities (QFs) under the Public
Utility Regulatory Policies Act of 1978, also would be recoverable
through non-bypassable rates, except that the recovery period would be
over the duration of the contract or any restructuring thereof.
CTCs associated with utility-owned fossil generation would be limited
to the uneconomic net book value of the fossil capital investment as
of January 1, 1998, plus the costs of capital additions subsequent to
December 20, 1995 that the CPUC determines are reasonable and
necessary to maintain the facilities through December 31, 2001.
Operating costs for such facilities would generally not be recoverable
except through market-based rates or if the facilities are required to
be operated for reliability purposes by the Independent System
Operator (ISO) to be developed in connection with restructuring, as
discussed below. PG&E will be permitted to retain any earnings from
the operation of such plants for reliability purposes, and will not be
required to apply those earnings to offset recovery of CTCs.
As discussed below, the recovery of CTCs must be consistent with not
increasing rates above rate levels in effect on June 10, 1996. The
CPUC's calculation of uneconomic costs associated with utility-owned
generation would be based on a mechanism which nets the negative value
of all above-market utility-owned generation assets against the
positive value of all below-market utility-owned generation. The
legislation provides that the CPUC's determination of the CTCs
eligible for recovery and of the valuation of the assets under these
criteria, which must occur by January 1, 2002, may not be rescinded or
altered by subsequent CPUC action.
The legislation provides for certain customers to be exempt from
paying CTCs. These exemptions include certain cogeneration and self-
generation projects, certain irrigation districts, the Bay Area Rapid
Transit District (BART), and the University of California at Davis.
Fifty million dollars of the costs attributable to the irrigation
district exemptions would be recoverable through March 31, 2002, but
the costs of the other exemptions would be recoverable only if
recovered by December 31, 2001, without raising rates in effect as of
June 10, 1996. The costs of such exemptions (other than the BART
exemption) may be allocated only to the customer classes of which the
exemptees are members.
Nuclear decommissioning costs would continue to be recovered through a
non-bypassable charge separate from CTCs until fully recovered.
Recovery of nuclear decommissioning costs may be accelerated.
The legislation cites the Restructuring Rate Settlement (Restructuring
Agreement) between PG&E and a spectrum of agricultural, commercial,
industrial, union, independent power and consumer groups, as an
example of a CTC cost recovery plan authorized by the legislation.
Rate Levels:
In order to provide utilities a reasonable opportunity to recover
their CTCs on an accelerated basis, the legislation, with certain
exceptions, requires that retail electric rates be set at levels equal
to those in effect as of June 10, 1996, and remain at those levels
until the earlier of March 31, 2002 or when CTCs have been fully
recovered. The June 10, 1996 rate level is inclusive of CTCs.
The legislation states that it is the Legislature's intent that
utilities be required and authorized to refinance the costs of CTCs
for residential and small commercial customers (customers who have
less than 20 kilowatts of peak demand) so that their rates will be
reduced no less than 10 percent for 1998 continuing through 2002. In
order to achieve this rate reduction, utilities are authorized to
finance a portion of their CTCs with proceeds from the sale of "rate
reduction bonds" issued by the California Infrastructure and Economic
Development Bank (IED Bank). The rate reduction bonds will have a
term not to exceed ten years. Residential and small commercial
customers will pay the principal and interest on the rate reduction
bonds through a separately identified component of their electric
utility bill. Utilities will act as collection agent, and will remit
principal and interest payments to the IED Bank or to a special
purpose trust authorized by the IED Bank to issue bonds. The
legislation requires that utilities, by no later than June 1, 1997,
apply concurrently to the CPUC and the IED Bank, respectively, for
financing orders and for issuance of rate reduction bonds sufficient
to accomplish the rate reduction for residential and small commercial
customers.
The legislation provides that financing orders issued by the CPUC and
rate proceeds made the basis of issuance of rate reduction bonds may
not be limited, altered, amended or rescinded by the CPUC or by the
State of California, except for adjustments to the amounts necessary
to ensure timely recovery of all transition costs financed by the
financing orders and rate reduction bonds.
The legislation also states that an anticipated result of
implementation of the legislation is that rates for residential and
small commercial customers would be reduced cumulatively by no less
than 20 percent by April 1, 2002, compared to rates in effect on June
10, 1996. The legislation provides that the CPUC will determine
whether the April 1, 2002 rate reduction has been met by excluding the
costs of competitively procured electricity and the costs associated
with the rate reduction bonds issued to finance a portion of CTCs.
Independent System Operator and Power Exchange/System Reliability
Standards:
The legislation requires the CPUC to facilitate the development of an
ISO and a Power Exchange (PX), and establishes a five-member Oversight
Board to (1) ensure that the ISO and PX are incorporated as public
benefit, non-profit corporations under California law; (2) oversee the
ISO and PX, (3) appoint members of the governing boards of the ISO and
PX, and (4) serve as an appeal board for appeals by ISO governing
board members from majority decisions of the ISO governing board.
Three members of the Oversight Board are to be California residents
and electric ratepayers appointed by the Governor from a list jointly
recommended by the CPUC and the California Energy Commission, and
subject to confirmation by the California State Senate. One member is
to be a member of the California State Assembly appointed by the
Speaker thereof, and one member is to be a member of the State Senate
appointed by the Committee on Rules thereof. The legislative members
will be non-voting members. Members of the Oversight Board will be
appointed for staggered three-year terms.
The ISO and PX Governing Boards are to be composed of California
residents, and will include, but are not limited to, representatives
of investor-owned utility transmission owners, publicly-owned utility
transmission owners, nonutility electricity sellers, public buyers and
sellers, private buyers and sellers, industrial end-users, commercial
end-users, residential end-users, agricultural end-users, public
interest groups, and non-market participant representatives. A simple
majority of the ISO Governing Board must be unaffiliated with electric
generation, transmission or distribution corporations.
It is the intent of the legislation that both California's investor-
owned utilities and its publicly-owned utilities commit control of
their transmission facilities to the ISO. Publicly-owned utilities
are authorized to recover their generation-related transition costs
through the imposition of exit fees if they have otherwise committed
their transmission system control to the ISO. The ISO is required to
ensure reliable transmission services consistent with planning and
operating reserve criteria no less stringent than those established by
the Western Systems Coordinating Council (WSCC) and the North American
Electric Reliability Council. Consistent with these criteria, the ISO
must adopt inspection and maintenance standards for investor-owned and
publicly-owned utilities no later than March 31, 1997.
Within six months of Federal Energy Regulatory Commission (FERC)
approval of establishment of the ISO, the ISO must provide a report to
the Legislature on current reliability criteria in the WSCC, the
economic cost of system outages and cost-effective options to prevent
them. The ISO is required to review the causes of major system
outages, and is authorized to order appropriate sanctions on
transmission owners responsible for such outages, subject to FERC
approving that authority. The CPUC is required to seek approval from
the FERC to give the ISO the authority to secure generating and
transmission resources necessary to meet the reliability criteria.
Finally, it is the intent of the legislation that California enter
into an interstate compact with other western states to establish
enforceable reliability standards for the interconnected regional
transmission and distribution systems.
The legislation requires that no later than March 31, 1997, the CPUC
adopt inspection, maintenance, repair and replacement standards for
the distribution systems of investor-owned utilities. In order to
assure reliability, in any sale (but not spin-off) of utility electric
generating facilities initiated prior to December 31, 2001 and
approved by the CPUC prior to December 31, 2002, the CPUC must require
that the selling utility contract with the purchaser for the selling
utility, an affiliate, or a successor corporation to operate and
maintain the facility for at least two years. This requirement would
not apply if the plant were shut down or otherwise not operated. The
CPUC may, but is not required to, impose these requirements on sales
initiated on or after January 1, 2002.
Direct Access:
The legislation authorizes direct transactions between electricity
suppliers and end-use customers, beginning no later than January 1,
1998, and on a phased-in schedule through December 31, 2001, that is
equitable to all customer classes. Aggregation of customer electrical
load for such direct transactions is authorized, provided that
customers consent to aggregation through a positive written
declaration. No change in the aggregator or electric service provider
of a residential or small commercial customer may be made unless the
change complies with certain "anti-slamming" provisions. Customers
would be eligible for direct transactions regardless of any phase-in
schedule if at least one-half the customer's electrical load is
supplied by a certified renewable resource provider.
Base Revenue Increases:
The legislation specifically provides for annual increases in base
revenues for PG&E, effective in 1997 and 1998, equal to the inflation
rate (as measured by the consumer price index) for the prior year plus
two percentage points. The base revenue increases do not affect the
overall electric rates for customers, which will be frozen, per the
legislation. The increase will remain in effect pending a general
rate case to be filed by PG&E no later than the end of 1997 for rates
to be effective in January 1999. However, these base revenue
increases will not create any presumption regarding the level of base
revenues to be used for any future base rate or performance-based
ratemaking. Further, the base revenue increases must be used for
enhancing transmission and distribution system safety and reliability,
and any such revenues not expended for such purposes shall be credited
against subsequent safety and reliability revenue requirements in
future years.
Regulation of Generation Facilities:
The legislation provides that generation facilities owned by a public
utility prior to January 1, 1997 and subject to rate regulation by the
CPUC will continue to be regulated by the CPUC only until the
facilities have undergone market valuation in connection with the CTC
recovery mechanism. However, if the public utility wishes to retain
ownership of the facility in the same corporation as its distribution
utility after market valuation has taken place, the utility must
demonstrate to the CPUC that such continued ownership in the same
corporation is in the public interest and would not confer an undue
competitive advantage on the utility.
The legislation also provides that owning, controlling, operating or
managing a power plant used for direct access or for sales to the PX
would not subject a corporation or person to CPUC regulation solely by
reason of such ownership, control, operation, management or sale.
Consumer Protection:
Except for utilities already regulated by the CPUC, entities which
offer electrical services to residential and small commercial
customers must register with the CPUC, provide specific information to
customers as part of its services, and be subject to specific claims
and damages procedures. This requirement would expire January 1, 2002
unless renewed by legislation. Existing utilities must develop
consumer information training programs to assist customers in
understanding their supply options under the new market structure.
All suppliers must follow verification procedures before customers may
be shifted from their current supplier.
Public Benefit Programs:
The legislation provides that energy efficiency, research and
development, and low income programs will be funded in electric rates
pursuant to a separate, non-bypassable charge at current levels from
January 1, 1998 through December 31, 2001. The June 10, 1996 rate
level is inclusive of this public benefit charge. Under this
provision, PG&E is obligated to fund energy efficiency and
conservation programs at $106 million per year; research and
development programs at $30 million per year; and renewable
technologies at not less than $48 million per year. The CTC recovery
period may be extended three months beyond December 31, 2001 to the
extent necessary to assure that the aggregate amount of funds
collected for renewable technologies programs from investor-owned
utilities is $540 million. Public interest funds not used for
transmission and distribution research, and renewable research and
development funds collected under these rates will be transferred to
and administered by the California Energy Commission. Publicly-owned
utilities must establish a public benefits charge commensurate to the
lowest expenditure of the investor-owned utilities, on a percent of
revenue basis.
Short Run Avoided Cost Pricing by QFs
The legislation provides that so-called "short run avoided cost
payments" paid by investor-owned utilities to nonutility generators,
including QFs, will be based on a formula which references the average
of current California natural gas border indices. When the CPUC
determines that the PX is functioning properly (see "Independent
System Operator and Power Exchange/System Reliability Standards,"
above), and either (1) the utility is subject to market-based rates
for its fossil generation unit, or (2) the utility has divested 90
percent of its gas fired generation units, the short run avoided cost
price will be based on the PX price. However, at any time, nonutility
generators may exercise a one-time option to base their short run
avoided cost price on the PX price.
Restructuring of Publicly Owned-Utilities
The legislation restructures the regulation and authority of publicly-
owned utilities in parallel with the provisions applicable to
investor-owned utilities, as follows:
- --Publicly-owned utilities will determine whether to offer direct
access on their systems, subject to a phase-in period commencing no
later than January 1, 2000;
- --If the publicly-owned utility offers direct access, it may establish
a non-bypassable CTC charge;
- --After the ISO is approved, neither a publicly-owned utility nor an
investor-owned utility may recover CTCs under the legislation unless
it has committed control of its transmission facilities to the ISO;
and
- --The legislation reflects an agreement between local publicly-owned
electric utilities and investor-owned utilities on pricing principles
for transmission facilities committed to the ISO. Initially, utility
specific access charges and rates will honor all of the terms and
conditions of existing transmission services contracts and will
recognize any wheeling revenues of existing transmission service
arrangements to the particular transmission owner. No later than two
years after the initial operation of the ISO, the ISO will recommend a
revised rate structure. If the ISO transmission rates are different
than those in effect for any transmission facility owner, the amount
of any difference may be tracked and recovered in rates over an
amortization period which would commence after termination of the
period for recovery of CTC costs.
B. CPUC Reform Legislation
In conjunction with its adoption of comprehensive legislation
restructuring the electric utility industry, the California
Legislature also enacted legislation which, if signed by the Governor,
would implement certain reforms to the structure and procedures of the
CPUC and for judicial review of certain CPUC proceedings. Among other
things, the legislation (SB960 and SB1322) modifies the process for
selecting the head of the Division of Ratepayer Advocates (DRA), by
making that position one filled by and serving at the pleasure of the
Governor, subject to confirmation by the California Senate. Currently
the director of the DRA, which under the legislation would remain a
division of the CPUC whose mission is to represent the interests of
public utility customers in CPUC proceedings, is appointed by the
CPUC. The legislation would also institute new procedures for
classifying and processing various type of CPUC proceedings. The
legislation requires the CPUC to classify proceedings either as
adjudicatory, ratesetting or quasi-legislative, and to employ
different ex parte rules and hearing procedures depending on the
classification. Generally, ex parte contacts with decision makers are
prohibited in adjudicatory proceedings (defined as complaint cases and
enforcement-type proceedings), are limited in ratesetting proceedings
in a manner to provide all parties with an equal opportunity to engage
in such contacts, and are unlimited in quasi-legislative proceedings.
The legislation also modifies the mechanism for judicial review of
adjudicatory proceedings. Currently all appeals of CPUC decisions are
by discretionary writ directly to the California Supreme Court. Under
the legislation, appeals of adjudicatory proceedings may also be
requested of the California Court of Appeals.
C. California Public Utilities Commission Proceedings
1. Electric Industry Restructuring
a. Diablo Canyon/Rate Freeze Application
In March 1996, PG&E filed an application with the CPUC seeking
approval to modify the Diablo Canyon Rate Case Settlement (Diablo
Settlement) contingent upon the adoption of a five-year customer
electric rate freeze, effective January 1, 1997 (Diablo Canyon/Rate
Freeze Application). On August 29, 1996, the CPUC's DRA issued its
report and recommendations on PG&E's Diablo Canyon/Rate Freeze
Application.
In its report, the DRA indicates that it supports PG&E's endeavor to
eliminate its above-market generation costs by the year 2001, but DRA
recommends several modifications to PG&E's proposal. Among other
things, the DRA recommends changes to the performance-based
Incremental Cost Incentive Price (ICIP) mechanism to reduce the pre-
set price per kilowatt-hour (kWh) paid for plant output, which
escalates over the period 1997 - 2001. Revenues under the ICIP are
intended to recover Diablo Canyon Nuclear Power Plant's (Diablo
Canyon) variable costs and incremental capital additions. The ICIP
prices proposed by PG&E and recommended by the DRA are set forth in
the following table.
Proposed ICIP Prices
(per kWh) 1997 1998 1999 2000 2001
- ----------------------------------------------------
PG&E 3.60 3.71 3.83 3.98 4.19
DRA 2.80 2.90 2.95 2.95 3.00
As an alternative, the DRA proposes that the ICIP mechanism be
replaced by traditional cost of service recovery for Diablo Canyon
operating costs and capital additions.
In addition to the ICIP, PG&E has proposed a sunk cost revenue
requirement consisting of PG&E's remaining sunk costs in Diablo Canyon
at December 31, 1996, depreciated over a five-year period, which would
be recovered regardless of Diablo Canyon's performance. The DRA
recommends various disallowances that would reduce the amount of the
sunk cost revenue requirement that could be recovered. In particular,
the DRA recommends disallowing $78 million in nuclear fuel inventory,
$40 million in post-2001 tax benefits the DRA alleges should be flowed
through to ratepayers, and an unspecified amount due to allegedly
excessive profits PG&E has or may earn on Diablo Canyon generation.
In its report, the DRA adopts PG&E's rate freeze proposal, but
proposes that residential and small customer rates be reduced by 10%
over the five-year freeze period. The DRA states that this 10% rate
reduction would be in addition to any rate reductions mandated by the
California State Legislature.
Hearings on the Diablo Canyon/Rate Freeze Application are scheduled
for October 1996, with a decision currently expected in March 1997.
b. CTC Application
Pursuant to the CPUC's December 1995 electric industry restructuring
decision, on August 30, 1996, PG&E submitted its application to
establish a competition transition charge (CTC). The purpose of the
application (CTC Application) is to (1) establish a methodology for
calculating the CTC, (2) identify costs included in the CTC, (3)
establish the ratemaking mechanism required to recover generation
costs and the CTC, (4) describe the CTC responsibility for departing
load and (5) estimate the CTC for calendar year 1998.
PG&E's CTC Application represents another step in the process that
will ultimately determine the amount of CTC responsibility for each
customer rate class. PG&E's CTC proposal is consistent with the goals
articulated in the CPUC's electric industry restructuring decision and
reflects the terms of PG&E's Diablo Canyon/Rate Freeze Application.
In addition, the filing recognizes that electric industry
restructuring legislation, if enacted, will require PG&E to modify and
supplement the CTC Application.
CTC Recovery Method:
In its CTC Application, PG&E notes that since it has proposed to take
on the risk of recovery of its utility generation CTC through its rate
freeze proposal and accelerated CTC recovery schedule it should have a
ratemaking mechanism to collect CTC that gives PG&E flexibility in
recovering CTC and the ability to bring non-nuclear generation assets
to a level approximating their market value. PG&E would be at risk
for completing recovery of PG&E's above-market utility generation-
related investments, including generation plant and related regulatory
assets by the end of 2001.
Consistent with PG&E's preliminary unbundling proposal, filed with the
CPUC in July 1995, PG&E proposes to measure CTC revenues on a residual
basis, (i.e., the costs of distribution, transmission, generation and
public purpose programs and other non-bypassable charges, such as
nuclear decommissioning, will be subtracted from the "frozen" bundled
rates and the amount that remains will be applied to transition
costs). Under PG&E's proposal, PG&E would collect all CTC-related
revenues in a single account that would be used to recover CTC costs
in the following order:
(1) the current year costs, including the revenue requirement for
Diablo Canyon sunk costs and the ICIP, revenue requirements associated
with the depreciation of non-nuclear utility generation plant and QF
and other power purchase agreements and QF restructuring costs;
(2) accelerated recovery of costs for which CTC recovery must be
completed by the end of 2001, including generation-related regulatory
assets, and above-market plant costs; and
(3) CTC costs that may be recovered after 2001, including
restructuring implementation costs (e.g., ISO, PX and direct access
implementation costs), employee transition costs, and QF and other
power purchase agreements revenue requirements and QF restructuring
costs after 2001.
In its CTC Application, PG&E requests the flexibility to use available
CTC revenues to recover eligible costs in this priority order in order
to minimize the potential for write-offs under the proposed shortened
CTC recovery period. PG&E indicates that such flexibility is also
required in order to allow PG&E the opportunity to accelerate non-
nuclear generation plant balances so that the net book value of the
plant will approximate the plant's market value so as to reduce the
probability that PG&E would have write-offs due to inconsistent
treatment between regulation and financial accounting.
If CTC revenues through 2001 are insufficient to recover PG&E's
uneconomic costs related to its generation plant and related
regulatory assets, PG&E would incur a loss. Should CTC revenues
exceed these costs, they would be used to reduce those CTC costs
eligible for recovery beyond 2001.
PG&E's proposals in the Diablo Canyon Rate Freeze Application, its
generation performance-based ratemaking application filed in July
1996, and the CTC Application would eliminate the need for Energy Cost
Adjustment Clause reasonableness reviews for generation, power plant
fuel and power purchase costs.
Costs Included in CTC:
PG&E's filing indicates that CTCs are generally composed of sunk
costs, ongoing costs and implementation costs. PG&E proposes to
include in CTC the following categories of costs:
(1) Above-market portion of Diablo Canyon;
(2) Fossil generation sunk costs;
(3) Future fixed and variable operating costs and future capital
additions for fossil "constrained-on" generation plants (i.e.,
fossil plants that are required to operate to maintain
transmission system reliability as designated by the ISO) to the
extent not recovered under reliability contracts with the ISO;
(4) Hydroelectric and geothermal generation sunk costs, ongoing
operating costs and future capital additions;
(5) Cost of the sunk cost audit to be completed in connection with
PG&E's August 1996 sunk cost filing with the CPUC;
(6) QF and other power purchase agreements;
(7) Generation-related regulatory assets and obligations;
(8) ISO, PX and direct access implementation costs;
(9) Employee transition costs; and
(10) Generation divestiture transaction costs.
Estimate of CTCs:
PG&E's filing presents an estimate of CTC expected in 1998, assuming
that the Diablo Canyon/Rate Freeze Application and CTC provisions of
the Restructuring Agreement are approved by the CPUC. Assuming a
market price of $0.026 per kWh in 1998, PG&E expects that CTC in 1998
will range from $2.2 billion (PG&E's current year costs for 1998) to
$2.8 billion (which would include accelerated recovery of non-nuclear
generation plant and regulatory assets).
Any estimate of CTCs constitutes a forward-looking statement. Certain
factors, including most importantly, actual market prices in the
future and future valuation of generation assets in a restructured
market, may cause actual results to differ materially from those
anticipated in those forward-looking statements.
CTC Responsibility for Departing Loads:
PG&E's filing proposes a separate CTC ratemaking mechanism for
"departing load" customers, i.e., those customers who discontinue
their purchases of electricity supplied or delivered by PG&E and
replace that usage with electricity that is both supplied and
delivered by some other means. PG&E proposes that CTC be collected
from those customers using a combination of ongoing and lump sum
payments.
2. 1997 Cost of Capital
On August 26, 1996, the DRA, PG&E and all other active parties agreed
to jointly recommend a return on common equity (ROE) of 11.60% for
PG&E's authorized cost of capital for 1997, which represents no change
from PG&E's currently authorized ROE. PG&E had originally requested
an ROE of 11.85%, while the DRA had recommended 11.25%. The joint
recommendation also recommends adoption of a capital structure of
48.0% common equity, 5.8% preferred stock and 46.2% long-term debt,
which is a slight change from the current capital structure of 48.0%
common equity, 5.5% preferred stock and 46.5% long-term debt. When
combined with the estimated costs of debt and preferred stock, the
recommended 11.60% return on common equity results in an overall rate
of return on utility rate base of 9.45% for 1997, compared with the
9.49% authorized for 1996.
If the joint recommendation is adopted, PG&E's electric and gas
revenues would decrease approximately $5 million and $2 million,
respectively. PG&E has requested that the electric revenue changes
associated with the cost of capital proceeding and other outstanding
rate proceedings be consolidated in order to achieve the customer
electric rate freeze proposed by PG&E in the Diablo Canyon/Rate Freeze
Application.
As part of its cost of capital application, PG&E had requested a
separate capital structure and cost of capital for PG&E's portion of
the PGT/PG&E Pipeline Expansion (PG&E Expansion). The joint
recommendation specifies an ROE of 11.60%, with a capital structure of
64% debt and 36% equity. PG&E's current ROE for the PG&E Expansion is
12.1%, with a capital structure of 67% debt and 33% equity, and it had
requested a 13.5% ROE for 1997. Adoption of the joint recommendation
is not expected to result in any change in revenue from the PG&E
Expansion.
Agreements with the DRA do not constitute a CPUC decision and are
subject to modification by the CPUC in its final decision. A final
CPUC decision on the parties' joint recommendation is expected in
November 1996.
PACIFIC GAS AND ELECTRIC COMPANY
GORDON R. SMITH
By ________________________________
GORDON R. SMITH
Senior Vice President and
Chief Financial Officer
Dated: September 9, 1996
