FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
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(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File No. 1-2348
PACIFIC GAS AND ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
California 94-0742640
- ---------------------------- -------------------
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
77 Beale Street, P.O. Box 770000, San Francisco, California 94177
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:(415) 973-7000
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding twelve months (or for
such shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes X No
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Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Class Outstanding at October 31, 1996
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Common Stock, $5 par value 412,249,278 shares
Form 10-Q
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TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION Page
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Item 1. Consolidated Financial Statements and Notes
Statement of Consolidated Income................... 1
Consolidated Balance Sheet......................... 2
Statement of Consolidated Cash Flows............... 4
Note 1: General
Basis of Presentation................... 5
Note 2: Electric Industry Restructuring........... 5
Note 3: Natural Gas Matters....................... 11
Note 4: Diablo Canyon............................. 12
Note 5: Contingencies
Nuclear Insurance....................... 12
Environmental Remediation............... 13
Helms Pumped Storage Plant.............. 14
Legal Matters........................... 14
Note 6: Company Obligated Mandatorily
Redeemable Preferred Securities
of Subsidiary Trust Holding Solely
PG&E Subordinated Debentures.............. 15
Item 2. Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Competition and Changing Regulatory
Environment
Electric Industry Restructuring................ 16
Gas Industry Restructuring..................... 22
Utility Revenue Matters........................ 24
Holding Company Structure.......................... 26
Results of Operations.............................. 27
Earnings Per Common Share........................ 28
Common Stock Dividend............................ 28
Operating Revenues............................... 28
Operating Expenses............................... 29
Liquidity and Capital Resources
Sources and Uses of Capital...................... 29
Environmental Remediation........................ 30
Legal Matters.................................... 30
PART II. OTHER INFORMATION
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Item 5. Helms Pumped Storage Plant......................... 31
Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends............ 32
Item 6. Exhibits and Reports on Form 8-K................... 32
SIGNATURE...................................................... 33
PART 1. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
---------------------------------
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(unaudited)
<CAPTION>
- ------------------------------------------------------------------------------------------------
Three months ended September 30, Nine months ended September 30,
(in thousands, ------------------------------- -------------------------------
except per share amounts) 1996 1995 1996 1995
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric utility $2,039,207 $2,132,425 $5,348,676 $5,723,878
Gas utility 453,270 479,058 1,473,592 1,529,703
Diversified operations 29,375 26,170 87,018 140,960
---------- ---------- ---------- ----------
Total operating revenues 2,521,852 2,637,653 6,909,286 7,394,541
---------- ---------- ---------- ----------
OPERATING EXPENSES
Cost of electric energy 749,023 686,852 1,746,809 1,609,580
Cost of gas 62,186 52,860 317,474 239,772
Maintenance and other operating 604,788 438,689 1,586,320 1,252,572
Depreciation and decommissioning 309,715 328,753 916,044 1,025,229
Administrative and general 201,634 273,956 727,775 749,669
Workforce reduction cost - - - (18,195)
Property and other taxes 69,660 74,631 228,249 224,603
---------- ---------- ---------- ----------
Total operating expenses 1,997,006 1,855,741 5,522,671 5,083,230
---------- ---------- ---------- ----------
OPERATING INCOME 524,846 781,912 1,386,615 2,311,311
---------- ---------- ---------- ----------
OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 16,425 17,570 62,116 50,515
Allowance for equity funds
used during construction 3,233 5,592 9,311 17,692
Other--net 5,606 8,495 19,261 25,915
---------- ---------- ---------- ----------
Total other income and
(income deductions) 25,264 31,657 90,688 94,122
---------- ---------- ---------- ----------
INCOME BEFORE INTEREST EXPENSE 550,110 813,569 1,477,303 2,405,433
---------- ---------- ---------- ----------
INTEREST EXPENSE
Interest on long-term debt 151,065 153,999 453,556 478,571
Other interest charges 10,275 12,122 46,652 40,459
Allowance for borrowed funds
used during construction (1,814) (3,049) (5,270) (9,132)
---------- ---------- ---------- ----------
Net interest expense 159,526 163,072 494,938 509,898
---------- ---------- ---------- ----------
PRETAX INCOME 390,584 650,497 982,365 1,895,535
---------- ---------- ---------- ----------
INCOME TAXES 156,889 272,904 376,186 783,735
---------- ---------- ---------- ----------
NET INCOME 233,695 377,593 606,179 1,111,800
Preferred dividend requirement
and redemption premium 8,279 15,901 24,835 44,889
---------- ---------- ---------- ----------
EARNINGS AVAILABLE FOR
COMMON STOCK $ 225,416 $ 361,692 $ 581,344 $1,066,911
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING 411,759 421,578 413,738 426,064
EARNINGS PER COMMON SHARE $.55 $.85 $1.41 $2.50
DIVIDENDS DECLARED PER COMMON SHARE $.49 $.49 $1.47 $1.47
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
September 30, December 31,
(in thousands) 1996 1995
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<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $18,009,732 $17,513,830
Diablo Canyon 6,687,283 6,646,853
Gas 7,961,822 7,732,681
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Total plant in service (at original cost) 32,658,837 31,893,364
Accumulated depreciation and decommissioning (14,138,535) (13,308,596)
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Net plant in service 18,520,302 18,584,768
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CONSTRUCTION WORK IN PROGRESS 288,895 333,263
OTHER NONCURRENT ASSETS
Nuclear decommissioning funds 822,046 769,829
Investments in nonregulated projects 973,873 869,674
Other assets 132,047 130,128
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Total other noncurrent assets 1,927,966 1,769,631
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CURRENT ASSETS
Cash and cash equivalents 161,480 734,295
Accounts receivable
Customers 1,223,570 1,238,549
Other 11,884 65,907
Allowance for uncollectible accounts (38,038) (35,520)
Regulatory balancing accounts receivable 468,895 746,344
Inventories
Materials and supplies 180,791 181,763
Gas stored underground 135,755 146,499
Fuel oil 30,064 40,756
Nuclear fuel 161,040 175,957
Prepayments 34,912 47,025
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Total current assets 2,370,353 3,341,575
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DEFERRED CHARGES
Income tax-related deferred charges 1,064,000 1,079,673
Diablo Canyon costs 368,334 382,445
Unamortized loss net of gain on reacquired debt 379,973 392,116
Workers' compensation and disability claims recoverable 283,896 297,266
Other 445,996 669,553
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Total deferred charges 2,542,199 2,821,053
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TOTAL ASSETS $25,649,715 $26,850,290
=========== ===========
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<FN>
(continued on next page)
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
September 30, December 31,
(in thousands) 1996 1995
- --------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,051,994 $ 2,070,128
Additional paid-in capital 3,755,008 3,716,322
Reinvested earnings 2,687,020 2,812,683
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Total common stock equity 8,494,022 8,599,133
Preferred stock without mandatory redemption provisions 402,056 402,056
Preferred stock with mandatory redemption provisions 137,500 137,500
Company obligated mandatorily redeemable preferred
securities of subsidiary trust holding solely
PG&E subordinated debentures 300,000 300,000
Long-term debt 7,965,248 8,048,546
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Total capitalization 17,298,826 17,487,235
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OTHER NONCURRENT LIABILITIES
Customer advances for construction 130,381 146,191
Workers' compensation and disability claims 271,400 271,000
Other 845,025 815,960
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Total other noncurrent liabilities 1,246,806 1,233,151
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CURRENT LIABILITIES
Short-term borrowings - 829,947
Long-term debt 254,178 304,204
Accounts payable
Trade creditors 400,968 413,972
Other 433,773 387,747
Accrued taxes 438,510 274,093
Deferred income taxes 127,437 227,782
Interest payable 154,315 70,179
Dividends payable 211,318 205,467
Other 369,162 504,973
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Total current liabilities 2,389,661 3,218,364
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DEFERRED CREDITS
Deferred income taxes 3,862,197 3,933,765
Deferred tax credits 382,991 393,255
Noncurrent balancing account liabilities 127,207 185,647
Other 342,027 398,873
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Total deferred credits 4,714,422 4,911,540
CONTINGENCIES (Notes 2, 3 and 5)
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TOTAL CAPITALIZATION AND LIABILITIES $25,649,715 $26,850,290
=========== ===========
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
Nine months ended September 30,
------------------------------
(in thousands) 1996 1995
- --------------------------------------------------------------------------------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 606,179 $1,111,800
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and decommissioning 916,044 1,025,229
Amortization 68,972 128,463
Gain on sale of DALEN - (13,107)
Deferred income taxes and tax credits--net (160,766) (189,512)
Allowance for equity funds used during construction (9,311) (17,692)
Other deferred charges 109,764 10,134
Other noncurrent liabilities 124,655 (33,366)
Noncurrent balancing account liabilities and
other deferred credits (115,286) (58,756)
Net effect of changes in operating assets
and liabilities
Accounts receivable 71,520 79,024
Regulatory balancing accounts receivable 277,449 341,267
Inventories 22,408 28,306
Accounts payable 33,022 36,760
Accrued taxes 164,417 154,952
Other working capital (39,562) 102,654
Other-net 63,760 50,385
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Net cash provided by operating activities 2,133,265 2,756,541
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CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (828,704) (641,897)
Allowance for borrowed funds used during construction (5,270) (9,132)
Nonregulated projects (141,364) (107,370)
Proceeds from sale of DALEN - 340,000
Other--net (54,613) (127,018)
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Net cash used by investing activities (1,029,951) (545,417)
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CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 168,596 116,095
Common stock repurchased (242,414) (449,692)
Preferred stock redeemed - (168,130)
Long-term debt issued 1,074,035 704,480
Long-term debt matured, redeemed or repurchased (1,214,108) (1,110,652)
Short-term debt redeemed--net (829,947) (418,381)
Dividends paid (634,499) (674,128)
Other--net 2,208 (8,861)
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Net cash used by financing activities (1,676,129) (2,009,269)
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NET CHANGE IN CASH AND CASH EQUIVALENTS (572,815) 201,855
CASH AND CASH EQUIVALENTS AT JANUARY 1 734,295 136,900
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CASH AND CASH EQUIVALENTS AT SEPTEMBER 30 $ 161,480 $ 338,755
========== ==========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 377,471 $ 389,934
Income taxes 419,503 849,934
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
NOTE 1: General
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Basis of Presentation:
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The accompanying unaudited consolidated financial statements of
Pacific Gas and Electric Company (PG&E) and its wholly owned and
controlled subsidiaries (collectively, the Company) have been
prepared in accordance with interim period reporting requirements.
This information should be read in conjunction with the Consolidated
Financial Statements and Notes to Consolidated Financial Statements
incorporated by reference in the 1995 Annual Report on Form 10-K.
In the opinion of management, the accompanying statements reflect all
adjustments which are necessary to present a fair statement of the
financial position and results of operations for the interim periods.
All material adjustments are of a normal recurring nature unless
otherwise disclosed in this Form 10-Q. Prior year's amounts in the
consolidated financial statements have been reclassified where
necessary to conform to the 1996 presentation. Results of operations
for interim periods are not necessarily indicative of results to be
expected for a full year.
NOTE 2: Electric Industry Restructuring
- ----------------------------------------
The California Public Utilities Commission (CPUC) ordered a
restructuring of California's electric industry through its
restructuring decision issued in December 1995. The CPUC's goal is
to provide a market structure that will reduce rates and allow
California consumers to choose among competing suppliers of
electricity. In accordance with the CPUC's restructuring decision,
in 1996 PG&E has filed numerous regulatory applications and
proposals, including a proposal to modify the Diablo Canyon Nuclear
Power Plant (Diablo Canyon) rate case settlement as modified in 1995
(Diablo Settlement), a generation performance-based ratemaking (PBR)
proposal, an unbundling proposal to separate PG&E's rates to reflect
the different services provided, a competition transition charge
(CTC) recovery application, power exchange (PX) and independent
system operator (ISO) applications, and generation divestiture and
corporate restructuring comments.
In September 1996, comprehensive legislation on electric industry
restructuring (restructuring legislation) was signed into law. The
legislation adopts the basic tenets of the CPUC's restructuring
decision, including recovery of utilities' transition costs (costs
which are above market and could not be recovered under market-based
pricing). The restructuring legislation builds on PG&E's earlier
proposals, including its Diablo Settlement modification and customer
electric rate freeze proposal, filed in March 1996, and also provides
guidance to the CPUC on a number of implementation issues. The
restructuring legislation was supported by a broad coalition of
interest groups and will require numerous regulatory filings or
modifications to existing filings prior to its implementation.
Key elements of the restructuring legislation include: (1) a
nonbypassable CTC for recovery of transition costs; (2) a 10 percent
rate reduction for residential and small commercial customers
starting in 1998 to be financed by "rate reduction bonds;" (3) a rate
freeze for industrial, agricultural and large commercial customers at
current levels through no later than March 31, 2002; (4) direct
access for certain customers beginning no later than January 1, 1998,
and phased-in for the remaining customers through December 31, 2001;
(5) a PX; and (6) an ISO to manage and control the transmission
system and ensure system reliability.
The restructuring legislation authorizes California utilities to file
cost-recovery plans to recover their generation-related transition
costs from customers through a nonbypassable CTC included as part of
rates. Transition costs will be recovered under rates established by
the restructuring legislation by December 31, 2001, except as
follows: (1) employee-related transition costs are recoverable
through December 31, 2006; (2) transition costs associated with
existing Qualifying Facility (QF) and power purchase contracts are
recoverable over the duration of the contracts or any restructuring
thereof; (3) nuclear decommissioning costs will continue to be
recovered through a nonbypassable charge separate from the CTC until
fully recovered; and (4) amounts related to certain CTC exemptions
are recoverable through March 31, 2002.
The determination of the transition costs associated with utility-
owned generation will be based on the aggregate of above-market
values and below-market values of utility-owned generation assets.
The legislation provides that the CPUC will determine the amount of
utility-owned generation-related transition costs eligible for
recovery, and once quantified, the amounts eligible may not be
rescinded or altered by subsequent CPUC action. The restructuring
legislation permits accelerated recovery of transition costs
associated with PG&E-owned generation plants at a reduced return.
The reduced return is based on PG&E's weighted average cost of
capital where the common equity component is set at 90 percent of the
long-term cost of debt.
In order to provide utilities a reasonable opportunity to recover
their transition costs, the legislation requires that retail electric
rates be set at levels equal to those in effect as of June 10, 1996,
except for the rate reduction discussed below, and remain at those
levels until the earlier of March 31, 2002, or when transition costs
have been fully recovered.
The restructuring legislation provides for a rate reduction for
residential and small commercial customers (customers who have less
than 20 kilowatts of peak demand) of at least 10 percent by 1998,
compared to rates in effect on June 10, 1996. In order to achieve
the 10 percent rate reduction, utilities are authorized to finance a
portion of their transition costs with proceeds from the sale of
"rate reduction bonds" issued by the California Infrastructure and
Economic Development Bank.
The restructuring legislation also specifically provides for annual
increases in base revenues (nonfuel-related costs) for PG&E,
effective in 1997 and 1998, equal to the inflation rate for the prior
year plus two percentage points, under the condition that such
revenues be used for enhancing transmission and distribution system
safety and reliability. Any such revenues not expended for such
purposes shall be credited against subsequent safety and reliability
revenue requirements in future years. The base revenue increases
will not affect the overall electric rates for customers, which will
be set based upon the legislation.
The impact of the restructuring legislation on the CPUC's
restructuring decision and PG&E's various regulatory applications and
proposals are discussed below.
In March 1996, PG&E filed an application with the CPUC seeking
approval to modify the Diablo Settlement and freeze customer electric
rates. As a result of the rate treatment mandated by the
restructuring legislation and its specific reference to PG&E's
restructuring rate settlement (discussed below), PG&E believes that
the rate freeze portion of this application is superseded by the
restructuring legislation. The Company has filed a cost-recovery
plan with the CPUC to implement the provisions of the legislation
with a rate freeze effective January 1, 1997. The CPUC has requested
comments regarding the Company's filing. The Company expects a
decision in December 1996. Although the restructuring legislation
adopts the ratemaking methodology requested by the Diablo Settlement
modification proposal, the specific rates to be adopted for Diablo
Canyon are still subject to CPUC review. The requested ratemaking
methodology in the proposed settlement modification would reduce the
amount of Diablo Canyon transition costs compared to transition costs
that would arise under existing Diablo Canyon prices, while
recovering the Diablo Canyon investment and other above-market
utility generation assets by no later than the end of 2001. PG&E
would be at risk for completing recovery of PG&E's above-market
utility generation-related investments, including its investment in
Diablo Canyon by the end of 2001. PG&E's application would result in
the termination of the Diablo Settlement by the end of 2001, at which
time the price of Diablo Canyon generation would be determined by the
market consistent with the goals of the restructuring legislation.
Certain fixed or safety-related costs, such as decommissioning costs,
would continue to be recovered in PG&E's base rates without reference
to Diablo Canyon's performance.
In June 1996, PG&E entered into a restructuring rate settlement with
several parties representing consumers, labor and independent
electricity producers. This settlement endorses PG&E's Diablo
Settlement modification proposal and certain principles governing
restructuring of PG&E's electric business which will be reflected in
PG&E's filings. In October 1996, PG&E submitted a cost recovery plan
to the CPUC which incorporates PG&E's Diablo Settlement modification
proposal and restructuring rate settlement.
The CPUC's Office of Ratepayer Advocates (ORA) issued its report and
recommendations on PG&E's Diablo Settlement modification proposal in
August 1996. In its report, the ORA recommends, among other things,
various disallowances that would reduce the amount of costs that
would be eligible for transition cost recovery. The ORA's report
will be considered by the CPUC when it decides whether to approve
PG&E's application. A proposed decision on PG&E's Diablo Settlement
modification proposal is scheduled for February 1997, with a final
decision expected in late March 1997.
In March 1996, PG&E filed comments with the CPUC indicating that it
is willing to proceed with voluntary divestiture of at least 50
percent of its fossil-fueled generation assets, as long as CTC
recovery is satisfactorily resolved. In October 1996, PG&E announced
its plans to file with the CPUC for approval to sell four fossil-
fueled power plants. The potential sale of these plants would comply
with the CPUC restructuring directive that the state's utilities
voluntarily divest at least 50 percent of their fossil-fueled power
plants. PG&E expects to file its plan with the CPUC for the sale of
these plants later this year and will seek to sign sales agreements
with buyers before the end of 1997. Consistent with the
restructuring legislation, for the first two years after any sale,
buyers would be required to retain PG&E to operate and maintain the
plants.
In October 1996, PG&E submitted an update to its August 1996 CTC
application to reflect changes due to the restructuring legislation.
In its CTC application, PG&E requests the flexibility to use
available CTC-related revenues to recover eligible costs so as to
minimize the potential for write-offs under the shortened CTC
recovery period. In addition, PG&E proposes a new ratemaking process
whereby costs that are currently recovered through the energy cost
adjustment clause and the generation portion of the electric revenue
adjustment mechanism be recovered through generation revenues, which
include CTC cost recovery.
PG&E proposes that costs eligible for CTC recovery include: (1) sunk
costs (costs that are fixed and unavoidable) associated with utility
nonnuclear generating facilities incurred in the past and currently
collected through rates, future costs, such as decommissioning, and
costs associated with the sunk cost audit; (2) certain operating
costs associated with transmission-constrained power plants; (3) sunk
costs associated with Diablo Canyon; (4) above-market costs
associated with QF and other power purchase agreements; (5)
generation-related regulatory assets and obligations; (6) ISO, PX and
direct access implementation costs and employee transition costs; and
(7) generation divestiture transaction costs. PG&E proposes to
collect Diablo Canyon operating costs directly from non-CTC revenues.
Nuclear decommissioning costs would be collected through a separate
surcharge consistent with the restructuring legislation.
In August 1996, the CPUC conditionally approved a joint application
by PG&E and the other two California investor-owned electric
utilities which establishes two tax-exempt trusts for the purpose of
overseeing the costs associated with the development of the ISO and
PX. The development costs are estimated to range between $200 and
$300 million and would be financed through bank loans to the trust
supported by guarantees by PG&E and the other two utilities. PG&E
would guarantee a maximum of $112.5 million of such costs. Under the
restructuring legislation the funds derived from the financing are to
be made available to the ISO and PX governing boards for use in
developing those entities. These amounts will be repaid through
future ISO tariffs and PX revenues or may be recovered as part of the
CTC.
Consistent with the CPUC's restructuring decision, in July 1996, PG&E
submitted an application proposing to establish a PBR mechanism for
its hydroelectric and geothermal generating unit costs. The proposed
mechanism consists of a base revenue amount that is indexed to
account for inflation less a productivity offset and includes a
shared earnings mechanism. Adjustments would be made to account for
fuel costs, performance standards and extraordinary costs or savings.
The hydroelectric and geothermal PBR would begin on January 1, 1998,
and would terminate by the end of 2001, at which time all generation
would be priced at market levels.
Financial Impact of the Electric Industry Restructuring:
- -------------------------------------------------------
PG&E 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," which allows PG&E to capitalize, as regulatory
assets, certain costs that would otherwise have been expensed. In
addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of," requires that
regulatory assets be written off when they are no longer probable of
recovery and that impairment losses be recorded for long-lived assets
when related future cash flows are less than the current value of the
asset.
As a result of applying the provisions of SFAS No. 71, PG&E had
accumulated approximately $1.4 billion of regulatory assets
attributable to electric generation at September 30, 1996. The net
investment in Diablo Canyon and the remaining PG&E-owned generation
assets, including an allocation of common plant, was approximately
$4.6 billion and $2.8 billion, respectively, at September 30, 1996.
The net present value of the above-market QF power purchase
obligations is estimated to be $5.3 billion at January 1, 1998, at an
assumed market price of $.025 per kilowatt-hour (kWh) beginning in
1997 and escalated at 3.2 percent per year. (The above amounts would
vary depending on allocation methods used.)
Given the current regulatory environment, PG&E's transmission and
distribution businesses are expected to remain under the provisions
of SFAS No. 71.
PG&E believes the restructuring legislation establishes a definitive
transition to market-based pricing for electric generation. The
restructuring legislation includes a rate freeze through no later
than March 31, 2002 (the end of the transition period), and cost-
based recovery of transition costs, including generation-related
regulatory assets. Transition costs eligible for recovery and the
actual recovery mechanism must be approved by the CPUC. Approved
transition costs will be recovered through a nonbypassable CTC charge
from customers, including customers who choose an alternative
provider of electric generation. Based on the restructuring
legislation, PG&E believes it will continue to meet the requirements
of SFAS No. 71 through the transition period. At the conclusion of
the transition period, PG&E expects to discontinue the application of
SFAS No. 71 for the electric generation portion of its business.
Since PG&E anticipates it will have recovered its generation-related
regulatory assets during the transition period, PG&E does not expect
a material adverse impact on its financial position or results of
operation from discontinuing the application of SFAS No. 71. PG&E's
ability to recover its transition costs during the transition period
will be dependent on several factors including, among other things,
continued application of the regulatory framework established by the
restructuring legislation, the amounts of transition costs approved,
the market value of its generation plants, future sales levels, fuel
and operating costs, the market price of electricity and the
ratemaking methodology adopted for Diablo Canyon. Based on its
current evaluation of these factors, PG&E believes its generation-
related regulatory assets are probable of recovery and that its owned
generation plants are not impaired. However, a change in these
factors could affect the probability of recovery of these regulatory
assets and the determination of plant impairment and could result in
a material loss.
NOTE 3: Natural Gas Matters
- ----------------------------
In August 1996, PG&E submitted to the CPUC for its approval a Gas
Accord Settlement (the Accord). The Accord is the result of an
extensive negotiation process that was initiated by PG&E in 1995.
Parties to the Accord represent a broad coalition of customer groups
and industry participants including advocates for residential,
industrial and commercial customers, cogenerators, municipalities,
producers and marketers. The Accord must be approved by the CPUC
before it can be implemented.
The Accord would restructure PG&E's gas services and its role in the
gas market and establish gas transmission rates for the period July
1997 through December 2002. Additionally, the Accord would resolve
various regulatory issues including, among others, (1) PG&E's request
for recovery of costs related to its capacity commitments with
Transwestern Pipeline Company (Transwestern) through 1997; (2) the
disallowance ordered by the CPUC in connection with PG&E's 1988
through 1990 gas reasonableness proceeding which is pending in
separate CPUC matters; (3) recovery of certain capital costs
associated with the PG&E portion of the PGT/PG&E Pipeline Expansion
Project; and (4) recovery, through PG&E's Interstate Transition Cost
Surcharge (ITCS), of costs relating to capacity commitments with El
Paso Natural Gas Company and Pacific Gas Transmission Company (PGT)
for capacity used to serve PG&E's customers. As a result of the
agreed upon level of ITCS recovery, PG&E has increased its reserve
for these costs in the third quarter of 1996.
The Accord contemplates that traditional reasonableness proceedings
relating to PG&E's costs of gas procurement for its core gas
customers will be replaced with a core procurement incentive
mechanism (CPIM) for the period from June 1, 1994, through 1997. The
CPIM would allow PG&E to recover its core gas costs under a
performance incentive mechanism constructed around market-price
benchmarks.
In October 1996, PG&E submitted to the CPUC, as a supplement to the
Accord application, a revised CPIM, modeled after the pre-1998 CPIM,
to cover gas procurement costs for the period 1998 to 2002. All
costs associated with the purchase of core natural gas (including
commodity costs and all pipeline demand charges except for a portion
of Transwestern demand charges) would be included as a cost of gas
under this revised mechanism. PG&E has provided reserves for a
portion of Transwestern demand charges in the third quarter of 1996.
Transwestern demand charges are $28 million per year for PG&E's 200
million cubic feet per day of capacity through 2007.
PG&E had previously provided reserves relating to the gas regulatory
issues addressed by the Accord and recorded additional reserves of
$182 million ($.26 per share) associated with gas capacity
commitments and the Accord in the third quarter of 1996. PG&E
believes the ultimate resolution of the cost recovery of its capacity
commitments and the matters addressed by the Accord will not have a
material adverse impact on its financial position or results of
operations.
NOTE 4: Diablo Canyon
- ----------------------
In May 1995, the CPUC approved a modification to the pricing
provisions of the Diablo Settlement. Under the modification, the
prices for power produced by Diablo Canyon for 1996 through 1999 are
10.5, 10.0, 9.5 and 9.0 cents per kWh, respectively, effective
January 1. PG&E has the right to reduce the price below the amount
specified. All other terms and conditions of the Diablo Settlement
remain unchanged. Under the modified pricing, at full operating
power each Diablo Canyon unit would contribute approximately $2.7
million in revenues per day in 1996.
As discussed in Note 2, in connection with the CPUC's electric
industry restructuring decision, PG&E filed in March 1996 a proposal
to amend the current Diablo Settlement.
NOTE 5: Contingencies
- ----------------------
Nuclear Insurance:
- -----------------
PG&E is a member of Nuclear Mutual Limited (NML) and Nuclear Electric
Insurance Limited (NEIL). Under these policies, if the nuclear
generating facility of a member utility suffers a property damage
loss or a business interruption loss due to a prolonged accidental
outage, PG&E may be subject to maximum assessments of $28 million
(property damage) and $8 million (business interruption), in each
case per policy period, in the event losses exceed the resources of
NML or NEIL.
Federal law requires all utilities with nuclear generating facilities
to share in payment for claims resulting from a nuclear incident and
limits industry liability for third-party claims to $8.9 billion per
incident. Coverage of the first $200 million is provided by a pool
of commercial insurers. If a nuclear incident results in claims in
excess of $200 million, PG&E may be assessed up to $159 million per
incident, with payments in each year limited to a maximum of $20
million per incident.
Environmental Remediation:
- -------------------------
The Company records its environmental liabilities when site
assessments and/or remedial actions are probable and a range of
reasonably likely cleanup costs can be estimated. The Company
reviews its sites and measures the liability quarterly, by assessing
a range of reasonably likely costs for each identified site using
currently available information, including existing technology,
presently enacted laws and regulations, experience gained at similar
sites and the probable level of involvement and financial condition
of other potentially responsible parties. These estimates include
costs for site investigations, remediation, operations and
maintenance, monitoring and site closure. Unless there is a probable
amount, the Company records the lower end of this reasonably likely
range of costs (classified as other noncurrent liabilities). The
Company may be required to pay for remedial action at sites where the
Company has been or may be a potentially responsible party under the
Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) or the California Hazardous Substance Account Act. These
sites include former manufactured gas plant sites and sites used by
PG&E for the storage or disposal of materials which may be determined
to present a significant threat to human health or the environment
because of an actual or potential release of hazardous substances.
Under CERCLA, the Company's financial responsibilities may include
remediation of hazardous wastes, even if the Company did not deposit
those wastes on the site.
The overall costs of the hazardous materials and hazardous waste
compliance and remediation activities ultimately undertaken by the
Company are difficult to estimate, and it is reasonably possible that
a change in the estimate will occur in the near term due to
uncertainty concerning the Company's responsibility, changing
environmental laws and regulations, evolving technologies, the nature
and extent of required remediation, the selection of compliance
alternatives and the ultimate outcome of factual investigations. The
Company had an accrued liability at September 30, 1996, of $169
million for hazardous waste remediation costs at those sites where
such costs are probable and quantifiable. The costs may be as much
as $386 million if, among other things, other potentially responsible
parties are not financially able to contribute to these costs or
further investigation indicates that the extent of contamination or
necessary remediation is greater than anticipated at sites for which
the Company is responsible. This upper limit of the range of costs
was estimated using assumptions less favorable to the Company, among
a range of reasonably possible outcomes. Costs may be higher if the
Company is found to be responsible for cleanup costs at additional
sites or identifiable possible outcomes change.
The Company will seek recovery of prudently incurred hazardous waste
compliance and remediation costs through ratemaking procedures
approved by the CPUC, through insurance and through other recoveries
from third parties. The Company had recorded a regulatory asset at
September 30, 1996, of $139 million for recovery of these costs in
future rates. While the Company has numerous insurance policies that
it believes may provide coverage for some of these liabilities, it
does not recognize insurance or third-party recoveries in its
financial statements until they are realized. The Company believes
the ultimate outcome of these matters will not have a material
adverse impact on its financial position or results of operations.
Helms Pumped Storage Plant (Helms):
- ----------------------------------
Helms is a three-unit hydroelectric combined generating and pumped
storage plant with a net investment of $711 million at September 30,
1996. The net investment is comprised of the pumped storage facility
(including regulatory assets of $51 million), common plant and
dedicated transmission plant. As part of the 1996 General Rate Case
decision issued in December 1995, the CPUC directed PG&E to perform a
cost effectiveness study of Helms. In July 1996, PG&E submitted its
study, which concluded that the continued operation of Helms is cost-
effective. PG&E recommended that the CPUC take no action as a result
of the study but address Helms along with other generating plants in
the context of electric industry restructuring.
PG&E is currently unable to predict whether there will be a change in
rate recovery resulting from the study. As with its other
hydroelectric generating plants, PG&E expects to seek recovery of its
net investment in Helms through the proposed hydroelectric and
geothermal PBR and CTC mechanisms (see Note 2). The Company believes
that the ultimate outcome of this matter will not have a material
adverse impact on its financial position or results of operations.
Legal Matters:
- -------------
In 1994, the City of Santa Cruz filed a class action suit in a state
superior court (Court) against PG&E on behalf of itself and 106 other
cities in PG&E's service area. The complaint alleges that PG&E has
underpaid electric franchise fees to the cities by calculating fees
at different rates from other cities.
In September 1995, the Court certified the class of 107 cities in
this action and approved the City of Santa Cruz as the class
representative. In January and March 1996, the Court made two
rulings against certain plaintiffs effectively eliminating a major
portion of the class action. The Court's rulings do not resolve the
case completely. The plaintiffs appealed both rulings. The trial
has been postponed pending the plaintiffs' appeal.
Should the cities prevail on the issue of franchise fee calculation
methodology, PG&E's annual systemwide city electric franchise fees
could increase by approximately $17 million and damages for alleged
underpayments for the years 1987 to 1995 could be as much as $131
million (exclusive of interest, estimated to be $37 million at
September 30, 1996).
If the Court's January and March 1996 rulings become final, PG&E's
annual systemwide city electric franchise fees for the remaining
class member plaintiffs not subject to the Court's rulings could
increase by approximately $5 million and damages for alleged
underpayments for the years 1987 to 1995 could be as much as $35
million (exclusive of interest, estimated to be $10 million at
September 30, 1996).
The Company believes that the ultimate outcome of this matter will
not have a material adverse impact on its financial position or
results of operations.
NOTE 6: Company Obligated Mandatorily Redeemable Preferred
Securities
- ---------------------------------------------------------------------
- -
of Subsidiary Trust Holding Solely PG&E Subordinated Debentures:
- ---------------------------------------------------------------
PG&E through its wholly owned subsidiary, PG&E Capital I (Trust), has
outstanding 12 million shares of 7.90% cumulative quarterly income
preferred securities (QUIPS), with an aggregate liquidation value of
$300 million. Concurrent with the issuance of the QUIPS, the Trust
issued to PG&E 371,135 shares of common securities with an aggregate
liquidation value of approximately $9 million. The only assets of
the Trust are deferrable interest subordinated debentures issued by
PG&E with a face value of approximately $309 million, an interest
rate of 7.90 percent and a maturity date of 2025.
Item 2. Management's Discussion and Analysis of Consolidated
----------------------------------------------------
Results of Operations and Financial Condition
---------------------------------------------
Pacific Gas and Electric Company (PG&E) and its wholly owned and
controlled subsidiaries (collectively, the Company) are engaged
principally in the business of supplying electric and natural gas
services. PG&E is a regulated public utility which provides
generation, procurement, transmission and distribution of electricity
and natural gas to customers throughout most of Northern and Central
California. Pacific Gas Transmission Company (PGT), a wholly owned
subsidiary, transports gas from the Canadian border to the California
border and the Pacific Northwest. The Company's operations are
regulated by the California Public Utilities Commission (CPUC), the
Federal Energy Regulatory Commission (FERC) and the Nuclear
Regulatory Commission (NRC), among others.
Building on its expertise in the energy industry, the Company is also
expanding its diversified operations, principally through its wholly
owned subsidiary, PG&E Enterprises (Enterprises). Enterprises,
through its subsidiaries and affiliates, develops, owns and operates
electric and gas projects around the world. In addition, PGT
recently completed its acquisition of a 389 mile natural gas
transportation system in the Australian State of Queensland.
The following discussion includes forward-looking statements that
involve a number of risks and uncertainties including but not limited
to the electric and gas industry restructuring and related filings.
When used in Management's Discussion and Analysis of consolidated
results of operations and financial condition, the words "estimates,"
"expects," "anticipates," "plans," and similar expressions are
intended to identify forward-looking statements that involve risks
and uncertainties. Importantly, the ultimate impact of increased
competition and the changing regulatory environment on future results
is uncertain but is expected to cause fundamental changes in the way
PG&E conducts its business and to make earnings more volatile. This
outcome and other matters discussed below may cause future results to
differ materially from historic results or from results or outcomes
currently expected or sought by the Company.
Competition and Changing Regulatory Environment
- -----------------------------------------------
Electric Industry Restructuring:
- -------------------------------
The CPUC ordered a restructuring of California's electric industry
through its restructuring decision issued in December 1995. The
CPUC's goal is to provide a market structure that will reduce rates
and allow California consumers to choose among competing suppliers of
electricity. In accordance with the CPUC's restructuring decision,
in 1996 PG&E has filed numerous regulatory applications and
proposals, including a proposal to modify the Diablo Canyon Nuclear
Power Plant (Diablo Canyon) rate case settlement as modified in 1995
(Diablo Settlement), a generation performance-based ratemaking (PBR)
proposal, an unbundling proposal to separate PG&E's rates to reflect
the different services provided, a competition transition charge
(CTC) recovery application, power exchange (PX) and independent
system operator (ISO) applications, and generation divestiture and
corporate restructuring comments. See Note 2 of Notes to
Consolidated Financial Statements for further discussion of electric
industry restructuring.
In September 1996, comprehensive legislation on electric industry
restructuring (restructuring legislation) was signed into law. The
legislation adopts the basic tenets of the CPUC's restructuring
decision, including recovery of utilities' transition costs (costs
which are above market and could not be recovered under market-based
pricing). The restructuring legislation also builds on PG&E's
earlier proposals, including its Diablo Settlement modification and
customer electric rate freeze proposal filed in March 1996, and also
provides guidance to the CPUC on a number of implementation issues.
The restructuring legislation was supported by a broad coalition of
interest groups and will require numerous regulatory filings or
modifications to existing filings prior to its implementation. The
restructuring legislation is described in greater detail in Note 2 of
Notes to Consolidated Financial Statements.
The impact of the restructuring legislation on the CPUC's
restructuring decision and PG&E's various regulatory applications and
proposals are discussed below.
In March 1996, PG&E filed an application with the CPUC seeking
approval to modify the Diablo Settlement and freeze customer electric
rates. As a result of the rate treatment mandated by the
restructuring legislation and its specific reference to PG&E's
restructuring rate settlement (described below), PG&E believes that
the rate freeze portion of this application is superseded by the
restructuring legislation. The Company has filed a cost-recovery
plan with the CPUC to implement the provisions of the legislation
with a rate freeze effective January 1, 1997. The CPUC has requested
comments regarding the Company's filing. The Company expects a
decision in December 1996. Although the restructuring legislation
adopts the ratemaking methodology requested by the Diablo Settlement
modification proposal, the specific rates to be adopted for Diablo
Canyon are still subject to CPUC review. The requested ratemaking
methodology in the proposed settlement modification would reduce the
amount of Diablo Canyon transition costs compared to transition costs
that would arise under existing Diablo Canyon prices, while
recovering the Diablo Canyon investment and other above-market
utility generation assets by no later than the end of 2001. After
2001, the price of Diablo Canyon generation would be determined by
the market consistent with the goals of the restructuring
legislation. Certain fixed or safety-related costs, such as
decommissioning costs, would continue to be recovered in PG&E's base
rates without reference to Diablo Canyon's performance. A proposed
decision is scheduled for February 1997, with a final decision
expected in late March 1997.
Under the Diablo Settlement modification proposal, the current Diablo
Canyon price would be replaced by a sunk cost revenue requirement and
an Incremental Cost Incentive Price (ICIP). Diablo Canyon sunk costs
include net plant, working capital and deferred assets, all net of
deferred taxes. The sunk cost revenue requirement for Diablo
Canyon, would include recovery of depreciation over a five-year
period and a return on common equity of 6.77 percent. Under the
ICIP, the variable costs and future capital additions would be
recovered under a pre-set price per kilowatt-hour (kWh) of plant
output based on an initial expectation of such costs and output.
Under the proposal, the 2016 termination date in the Diablo
Settlement would be changed to December 31, 2001, and related
abandonment payment provisions in the Diablo Settlement would be
replaced with closure cost recovery provisions, under which PG&E
would be entitled to recover a percentage of its annual operating and
maintenance and administrative and general costs for a limited number
of years following permanent plant closure. PG&E's continued
recovery of the sunk cost revenue requirement would be subject to
CPUC evaluation if Diablo Canyon is shut down for nine months or more
prior to such time as transition costs are fully recovered. After
such time as transition costs are fully recovered, there would be no
restrictions on Diablo Canyon's operations, to which customers it
could sell and at what prices, terms and conditions; however, 50
percent of any after-tax earnings available for common equity after
such time would be allocated to ratepayers.
Under the proposal, PG&E would be at risk for completing recovery of
its above-market utility generation-related investments, including
its investment in Diablo Canyon, by the end of 2001. Due to the rate
treatment mandated by the restructuring legislation, PG&E's proposal
to modify the Diablo Settlement and accelerate recovery of utility
generation-related investments (including Diablo Canyon) would not
adversely affect PG&E's cash flow but would result in a significant
reduction in annual earnings. If the revised return currently
contemplated for Diablo Canyon had been adopted for 1995 and PG&E
recovered no more than its actual costs under the performance-based
ICIP, Diablo Canyon's earnings available for common stock would have
been $115 million, as compared to $492 million. In addition, PG&E's
recovery of revenue based on the performance-based ICIP will depend
on the capacity factor and cost assumptions adopted by the CPUC in
implementing PG&E's Diablo Canyon pricing proposal. To the extent
that the actual capacity factor or expenses are different than those
adopted by the CPUC in setting the ICIP, the Company's earnings would
be impacted.
In June 1996, PG&E entered into a restructuring rate settlement with
several parties representing consumers, labor and independent
electricity producers. This settlement endorses PG&E's Diablo
Settlement modification proposal and certain principles governing
restructuring of PG&E's electric business which will be reflected in
PG&E's filings. In October 1996, PG&E submitted a cost recovery plan
to the CPUC which incorporates PG&E's Diablo Settlement modification
proposal and restructuring rate settlement.
In October 1996, PG&E submitted an update to its August 1996 CTC
application to reflect changes due to the restructuring legislation
and present estimates of total transition costs. Estimates of
transition costs are dependent on a number of assumptions. The most
critical parameter is the market price for electricity over the
transition period. Factors that could impact market prices include
changes in gas prices, sales levels, changes in inflation rates,
levels of new technology costs and the available supply of generation
within the market. To provide a range of possible total transition
costs, the estimates used market price assumptions of $.035, $.025
and $.015 per kWh, beginning in 1997 and escalated at 3.2 percent per
year, resulting in total estimated transition costs of $8.4 billion,
$11.4 billion and $14.1 billion, respectively (net present value at
January 1, 1998).
In its CTC application, PG&E requests the flexibility to use
available CTC-related revenues to recover eligible costs so as to
minimize the potential for write-offs under the shortened CTC
recovery period. In addition, PG&E proposes a new ratemaking process
whereby costs that are currently recovered through the energy cost
adjustment clause and the generation portion of the electric revenue
adjustment mechanism be recovered through generation revenues, which
include CTC cost recovery.
Under the restructuring legislation, PG&E would be at risk for
completing recovery of most transition costs by the end of 2001. The
restructuring legislation permits accelerated recovery of transition
costs associated with PG&E-owned generation plants at a reduced
return. The reduced return is based on PG&E's weighted average cost
of capital where the common equity component is set at 90 percent of
the long-term cost of debt.
Prior to adoption of the restructuring legislation, PG&E and the
other two California investor-owned electric utilities filed joint
ISO and PX applications with the FERC and the CPUC. These
applications requested authorization to transfer operational control
(but not ownership) of certain transmission facilities to the ISO and
to sell electric energy at market-based rates using the PX. In
October 1996, PG&E, the other two California utilities and two other
parties filed with the FERC joint comments addressing how the
restructuring legislation affects these applications.
In October 1996, the FERC approved a proposal from PG&E and the other
two California utilities that delineates between local distribution
facilities and transmission lines. The order marks the first federal
approval of a portion of California's restructuring proposal. It
also defines jurisdiction for the CPUC over local distribution and
retail power customers. The FERC will have jurisdiction over the
transmission lines defined in the three utilities' proposal.
PG&E will file its formal rate unbundling application with the CPUC
by December 6, 1996. That application will include a proposal to
separate total electric revenue requirements and the costs that
underlie them into various components which reflect the different
services provided. It is expected that the generation component will
be comprised of, among other things, CTC and nuclear decommissioning.
That application will also incorporate the FERC's resolution
regarding the delineation between distribution facilities and
transmission lines. The CPUC has also asked the utilities to provide
in a separate December filing information relating to the component
costs of hourly meters and billing and evaluations of alternative
strategies for installation of hourly meters under direct access.
PG&E has filed comments with the CPUC on the feasibility, timing and
consequences of a corporate restructuring to separate PG&E's
operations and assets between the generation, transmission and
distribution functions, indicating that, for the time being, it sees
no obvious benefits from separating its generation, transmission and
distribution functions into separate corporate subsidiaries.
However, PG&E believes that it may be appropriate in the future to
hold any generation it retains in a separate corporate entity.
In March 1996, PG&E filed comments with the CPUC indicating that it
is willing to proceed with voluntary divestiture of at least 50
percent of its fossil-fueled generation assets, as long as CTC
recovery is satisfactorily resolved. In October 1996, PG&E announced
its plans to file with the CPUC for approval to sell four fossil-
fueled power plants. The potential sale of these plants would comply
with the CPUC restructuring directive that the state's utilities
voluntarily divest at least 50 percent of their fossil-fueled power
plants. PG&E expects to file its plan with the CPUC for the sale of
these plants later this year and will seek to sign sales agreements
with buyers before the end of 1997. Consistent with the
restructuring legislation, for the first two years after any sale,
buyers would be required to retain PG&E to operate and maintain the
plants.
At the federal level, in April 1996, the FERC issued Order 888 which
requires utilities to provide wholesale open access to utility
transmission systems on terms that are comparable to the way
utilities use their own systems. PG&E filed a tariff in compliance
with Order 888 in July 1996. PG&E's tariff, which is almost
identical to the final tariff issued by the FERC as part of Order
888, is now available for service to any party interested in
wholesale transmission service over PG&E's transmission system. In
Order 888, the FERC reaffirmed its intention to permit utilities to
recover any legitimate, verifiable and prudently incurred generation-
related costs stranded as a result of customers taking advantage of
wholesale open access orders to meet their power needs from other
sources. The FERC also asserted that it has jurisdiction over the
transmission aspects of retail direct access.
Financial Impact of the Electric Industry Restructuring:
- -------------------------------------------------------
PG&E 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," which allows PG&E to capitalize as regulatory assets
costs that would otherwise have been expensed. In addition, SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of," requires that regulatory assets
be written off when they are no longer probable of recovery and that
impairment losses be recorded for long-lived assets when related
future cash flows are less than the current value of the asset.
As a result of applying the provisions of SFAS No. 71, PG&E had
accumulated approximately $1.4 billion of regulatory assets
attributable to electric generation at September 30, 1996. The net
investment in Diablo Canyon and the remaining PG&E-owned generation
assets, including an allocation of common plant, was approximately
$4.6 billion and $2.8 billion, respectively, at September 30, 1996.
The net present value of the above-market Qualifying Facility (QF)
power purchase obligations is estimated to be $5.3 billion at January
1, 1998, at an assumed market price of $.025 per kWh beginning in
1997 and escalated at 3.2 percent per year. (The above amounts would
vary depending on allocation methods used.)
Given the current regulatory environment, PG&E's transmission and
distribution businesses are expected to remain under the provisions
of SFAS No. 71.
PG&E believes the restructuring legislation establishes a definitive
transition to market-based pricing for electric generation. The
restructuring legislation includes a rate freeze through no later
than March 31, 2002(the end of the transition period), and cost-based
recovery of transition costs, including generation-related regulatory
assets. Transition costs eligible for recovery and the actual
recovery mechanism must be approved by the CPUC consistent with the
criteria established by the restructuring legislation. Approved
transition costs will be recovered through a nonbypassable CTC charge
from customers, including customers who choose an alternative
provider of electric generation. Based on the restructuring
legislation, PG&E believes it will continue to meet the requirements
of SFAS No. 71 through the transition period. At the conclusion of
the transition period, PG&E expects to discontinue the application of
SFAS No. 71 for the electric generation portion of its business.
Since PG&E anticipates it will have recovered its generation-related
regulatory assets during the transition period, PG&E does not expect
a material adverse impact on its financial position or results of
operation from discontinuing the application of SFAS No. 71. PG&E's
ability to recover its transition costs during the transition period
will be dependent on several factors including, among other things,
continued application of the regulatory framework established by the
restructuring legislation, the amounts of transition costs approved,
the market value of its generation plants, future sales levels, fuel
and operating costs, the market price of electricity and ratemaking
methodology adopted for Diablo Canyon. Based on its current
evaluation of these factors, PG&E believes its generation-related
regulatory assets are probable of recovery and that its owned
generation plants are not impaired. However, a change in these
factors could affect the probability of recovery of these regulatory
assets and the determination of plant impairment and could result in
a material loss.
The Company cannot predict the ultimate outcome of the ongoing
changes that are taking place in the electric utility industry.
However, the Company believes the end result will involve a
fundamental change in the way it conducts business. These changes
will impact financial operating trends, resulting in greater earnings
volatility.
Gas Industry Restructuring:
- --------------------------
PG&E is actively pursuing changes in the California gas industry in an
effort to promote competition and increase options for all customers, as
well as to position itself for success in the competitive marketplace.
In August 1996, PG&E submitted to the CPUC for its approval a Gas Accord
Settlement (the Accord), which would restructure PG&E's gas services and
its role in the gas market and establish gas transmission rates for the
period July 1997 through December 2002. The Accord must be approved by
the CPUC before it can be implemented.
The Accord consists of three broad initiatives:
(1) The Accord separates, or "unbundles," PG&E's gas transmission and
storage services from its distribution services and changes the terms of
service and rate structure for gas transportation so that customers'
rates more accurately reflect the cost of facilities used to serve them.
Unbundling will offer customers the opportunity to select from a menu of
services offered by PG&E and will enable them to pay only for the
services they use. PG&E will operate the unbundled transmission system
similar to an interstate pipeline. PG&E will be at risk for variations
in revenues resulting from differences between actual and forecasted
throughput. PG&E will also continue to provide distribution service,
much as it does today.
(2) The Accord reduces PG&E's role in procuring gas supplies for
core customers in order to increase opportunities for such customers to
purchase gas from their supplier of choice. The Accord also establishes
principles for continuing negotiations between PG&E and California gas
producers for the mutual release of supply contracts and the sale of gas
gathering facilities. PG&E will continue to procure gas as a regulated
utility supplier for those customers that request it. PG&E has proposed
that traditional reasonableness proceedings relating to its gas
procurement costs be replaced by a core procurement incentive mechanism
(CPIM). Under the CPIM, PG&E would receive benefits or penalties
depending on whether its actual core procurement costs were below or
above a "tolerance band" constructed around market benchmarks. The CPIM
proposal requests authorization to use derivative financial instruments
to reduce the risk of gas price and foreign currency fluctuations.
Gains, losses and transaction costs associated with the use of derivative
financial instruments would be included in the purchased gas account and
the measurement against the benchmarks. The Accord contemplates that the
CPIM be implemented for the period from June 1, 1994, through 1997, with
a revised CPIM for 1998 through 2002.
(3) The Accord resolves PG&E's major outstanding gas regulatory issues
including, among others, PG&E's recovery of certain capital costs
associated with the PG&E portion of the PGT/PG&E Pipeline Expansion
Project (PG&E Pipeline Expansion), recovery of costs related to PG&E's
capacity commitments with Transwestern Pipeline Company (Transwestern)
through 1997, the disallowance ordered by the CPUC in connection with
PG&E's 1988 through 1990 gas reasonableness proceeding, and the
Interstate Transition Cost Surcharge (ITCS) recovery of costs relating to
capacity commitments with El Paso Natural Gas Company and PGT for
capacity used to serve PG&E's customers. As a result of the agreed upon
level of ITCS recovery, PG&E has increased its reserve for these costs in
the third quarter of 1996. Under the Accord, PG&E would forgo recovery
of 100 percent and 50 percent of the ITCS amounts allocated to its core
and noncore customers, respectively. In addition, PG&E would agree to
set rates for the PG&E Pipeline Expansion based on total capital costs
which are lower than those actually incurred. With respect to
Transwestern costs, the Accord provides that PG&E would not recover costs
associated with Transwestern capacity originally subscribed to in order
to serve core customers through the end of 1997. Also as part of the
Accord, PG&E agrees to forgo recovery of the $90 million disallowance
ordered in the 1988 through 1990 gas reasonableness proceeding,
irrespective of the outcome of PG&E's pending lawsuit challenging that
disallowance.
In October 1996, PG&E submitted to the CPUC, as a supplement to the
Accord application, a revised CPIM, modeled after the pre-1998 CPIM, to
cover gas procurement costs for the period 1998 to 2002. All costs
associated with the purchase of core natural gas (including commodity
costs and all pipeline demand charges except a portion of Transwestern
demand charges) would be included as a cost of gas under this revised
mechanism. PG&E has provided reserves for a portion of Transwestern
demand charges in the third quarter of 1996. Transwestern demand charges
are $28 million per year for PG&E's 200 million cubic feet per day of
capacity through 2007.
PG&E had previously provided reserves relating to the gas regulatory
issues addressed by the Accord and recorded additional reserves of $182
million ($.26 per share) associated with gas capacity commitments and the
Accord in the third quarter of 1996. PG&E believes the ultimate
resolution of the cost recovery of its capacity commitments and the
matters addressed by the Accord will not have a material adverse impact
on its financial position or results of operations.
Utility Revenue Matters:
- -----------------------
In addition to electric industry restructuring (discussed above and in
Note 2 of Notes to Consolidated Financial Statements) and the Gas Accord
Settlement (discussed above and in Note 3 of Notes to Consolidated
Financial Statements), there are other regulatory matters with respect to
revenues and costs which will affect PG&E's rates in 1996 and beyond.
PG&E's 1996 General Rate Case (GRC) proceeding was held open to consider,
among other things, a study to determine the cost effectiveness of the
Helms Pumped Storage Facility (Helms). In July 1996, PG&E submitted its
study, which concluded that the continued operation of Helms is cost
effective. PG&E recommended that the CPUC take no action as a result of
the study but address Helms along with other generating plants in the
context of electric industry restructuring. PG&E is currently unable to
predict whether there will be a change in rate recovery resulting from
the study. As with its other hydroelectric generating plants, PG&E
expects to seek recovery of its net investment in Helms through proposed
hydroelectric and geothermal PBR and CTC mechanisms. The net investment
in Helms at September 30, 1996, was $711 million, comprised of the pumped
storage facility (including regulatory assets of $51 million), common
plant and dedicated transmission plant.
In September 1996, legislation on electric industry restructuring was
signed into law (see Electric Industry Restructuring above for further
discussion). The restructuring legislation freezes electric rates for
industrial, agricultural and large commercial customers at 1996 levels
through March 31, 2002, and decreases electric rates for residential and
small commercial customers by 10 percent in 1998. Revenue reductions
caused by the rate decreases are expected to be achieved by financing a
portion of PG&E's transition costs through rate reduction bonds.
The legislation also provides for annual increases in PG&E's 1997 and
1998 base revenues, equal to the inflation rate for the prior year plus
two percentage points. The revenues will be used for enhancing
transmission and distribution system reliability. Accordingly, in
October 1996, PG&E filed an advice letter with the CPUC requesting to
increase 1997 base revenues by $164 million.
The legislation provides the opportunity to offset revenue requirement
decreases with the accelerated recovery of transition costs. In 1997,
revenue requirement decreases would result from various pending
applications PG&E has filed with the CPUC, including the 1997 Energy Cost
Adjustment Clause (ECAC) application discussed below and the 1997 cost of
capital application also discussed below. In March 1996, PG&E filed an
application with the CPUC seeking approval to modify Diablo Canyon
pricing and to accelerate recovery of transition costs. The proposed
accelerated recovery would increase the 1997 Diablo Canyon revenue
requirement by $401 million. This increase would be substantially offset
by decreases in the Diablo Canyon revenues, resulting from the proposed
modified pricing. The effect of the modified pricing is incorporated in
the ECAC revenue requirement discussed below. (See Electric Industry
Restructuring above for further discussion of PG&E's Diablo Canyon
proposal.)
In October 1996, PG&E filed its updated 1997 ECAC application with the
CPUC. The updated filing requests a revenue requirement decrease of
approximately $718 million composed of an ECAC decrease of approximately
$555 million, an annual energy rate decrease of approximately $13
million, an energy revenue adjustment mechanism (ERAM) decrease of
approximately $147 million and a California alternative rates for energy
decrease of approximately $3 million.
The CPUC's Office of Ratepayer Advocates (ORA) has recommended that the
CPUC suspend implementation of ECAC rate reductions related to 1997
operations until March 31, 1997, on the assumption that this will allow
the CPUC to complete its analysis of PG&E's Diablo Settlement
modification proposal. The ORA also recommends that all ECAC
overcollections accrued from January 1, 1997, until the CPUC issues a
decision on the Diablo Settlement modification proposal be refunded to
ratepayers at that time. The ORA recommends that any ECAC overcollection
as of December 30, 1996, which the ORA estimates will be $88 million, be
returned to ratepayers as a one-time refund.
In October 1996, a CPUC Administrative Law Judge issued a proposed
decision adopting the joint recommendation of PG&E and other interested
parties for the following 1997 cost of capital:
<TABLE>
<CAPTION>
Capital Cost/ Weighted
Ratio Return Cost/Return
------- ------ -----------
<S> <C> <C> <C>
Common equity 48.00% 11.60% 5.57%
Preferred stock and preferred securities 5.80% 7.04% .41%
Long-term debt 46.20% 7.52% 3.47%
-----------
Total return on average utility rate base 9.45%
</TABLE>
If adopted, the joint recommendation would result in decreases of $5
million for the 1997 electric revenue requirement and $2 million for the
1997 gas revenue requirement effective January 1, 1997.
In October 1996, PG&E submitted an update to its August 1996 CTC
application to conform to the restructuring legislation. In the
application, PG&E proposes to supersede the ECAC and the generation
portion of the ERAM with a CTC mechanism commencing in 1998. (See
Electric Industry Restructuring for further discussion of the CTC
application.)
Holding Company Structure:
- -------------------------
The PG&E Board of Directors (Board) has authorized, and shareholders, the
CPUC and the FERC have approved, and the NRC has conditionally approved a
plan to restructure the corporate organization of PG&E and its
subsidiaries. The result of the change in corporate structure will be to
have PG&E become a separate subsidiary of a parent holding company
(ParentCo) with the present holders of PG&E common stock becoming holders
of ParentCo common stock. As part of the change in structure, it is
contemplated that PG&E will transfer its ownership interests in its two
principal subsidiaries, PGT and Enterprises, to ParentCo, so that PGT and
Enterprises will become subsidiaries of ParentCo. The debt and preferred
stock of PG&E would remain outstanding at the PG&E level and would not
become obligations or securities of ParentCo.
PG&E intends to form the holding company on or about January 1, 1997,
subject to Board approvals of certain matters.
Results of Operations
- ---------------------
The Company's revenues are derived from three types of operations:
utility (excluding Diablo Canyon and including PGT), Diablo Canyon and
diversified operations (principally Enterprises). The results of
operations for these areas for the three- and nine-month periods ended
September 30, 1996, and 1995, are reflected in the following table and
discussed below.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
September 30 Diablo Diversified
(in millions, except per share amounts) Utility Canyon Operations Total
<S> <C> <C> <C> <C>
1996
Operating revenues $ 1,999 $ 494 $ 29 $ 2,522
Operating expenses 1,773 188 36 1,997
------- ------ ------ -------
Operating income (loss) before income taxes $ 226 $ 306 $ (7) $ 525
======= ====== ====== =======
Net income $ 75 $ 158 $ 1 $ 234
======= ====== ====== =======
Earnings per common share $ 0.17 $ 0.38 $ 0.00 $ 0.55
======= ====== ====== =======
1995
Operating revenues $ 2,082 $ 530 $ 26 $ 2,638
Operating expenses 1,613 204 39 1,856
------- ------ ------ -------
Operating income (loss) before income taxes $ 469 $ 326 $ (13) $ 782
======= ====== ====== =======
Net income (loss) $ 211 $ 168 $ (1) $ 378
======= ====== ====== =======
Earnings per common share $ 0.46 $ 0.39 $ 0.00 $ 0.85
======= ====== ====== =======
NINE MONTHS ENDED
September 30 Diablo Diversified
(in millions, except per share amounts) Utility Canyon Operations Total
1996
Operating revenues $ 5,516 $1,306 $ 87 $ 6,909
Operating expenses 4,813 604 106 5,523
------- ------ ------ -------
Operating income (loss) before income taxes $ 703 $ 702 $ (19) $ 1,386
======= ====== ====== =======
Net income $ 255 $ 345 $ 6 $ 606
======= ====== ====== =======
Earnings per common share $ 0.57 $ 0.82 $ 0.02 $ 1.41
======= ====== ====== =======
Total assets at September 30 $19,136 $5,504 $1,010 $25,650
======= ====== ====== =======
1995
Operating revenues $ 5,715 $1,539 $ 141 $ 7,395
Operating expenses 4,324 578 181 5,083
------- ------ ------ -------
Operating income (loss) before income taxes $ 1,391 $ 961 $ (40) $ 2,312
======= ====== ====== =======
Net income $ 614 $ 490 $ 8 $ 1,112
======= ====== ====== =======
Earnings per common share $ 1.35 $ 1.13 $ 0.02 $ 2.50
======= ====== ====== =======
Total assets at September 30 $19,923 $5,795 $ 991 $26,709
======= ====== ====== =======
</TABLE>
Earnings Per Common Share:
- -------------------------
Utility earnings per common share for the three- and nine-month periods
ended September 30, 1996, were lower than for the comparable periods in
1995, reflecting revenue reductions authorized in the 1996 GRC and other
related rate proceedings. These reductions resulted from lower cost of
capital, declining capital expenditures and reductions in authorized
expense levels. Actual maintenance and other operating expenses for
distribution and customer-related services increased in 1996 and exceeded
levels authorized in the 1996 GRC. PG&E also recorded a charge of $.26
per common share for contingencies related to gas capacity commitments
and the Accord. Additionally, the settlement of outstanding litigation
decreased earnings for the nine-month period ended September 30,1996.
Diablo Canyon earnings per common share for the three- and nine-month
periods ended September 30, 1996, were lower than for the comparable
periods in 1995, due to a greater number of scheduled refueling days and
unscheduled outages in 1996. In addition, Diablo Canyon earnings per
common share for the current periods were reduced by a decline in the
price per kWh as provided in the pricing provisions of the Diablo
Settlement.
Common Stock Dividend:
- ---------------------
PG&E's common stock dividend is based on a number of financial
considerations, including sustainability, financial flexibility and
competitiveness with investment opportunities of similar risk. In
October 1996, the Board declared a quarterly common stock dividend of
$.30 per share, effective with the dividend payable on January 15, 1997,
which corresponds to an annual dividend of $1.20 per common share. This
represents a decrease from the previous annual dividend of $1.96 per
share. The Company plans to use cash resulting from the decreased
dividend payments to repurchase common stock, retire debt and more fully
pursue new growth opportunities. The Company has established a dividend
payout ratio objective (dividends declared divided by earnings available
for common stock) of between 50 and 65 percent (based on earnings
exclusive of nonrecurring adjustments).
Operating Revenues:
- ------------------
Operating revenues for the three- and nine-month periods ended September
30, 1996, decreased $119 million and $431 million, respectively, compared
to the same periods in l995. The decrease in both electric and gas
revenues was due to a decrease in authorized revenues as discussed above.
Additionally, Diablo Canyon operating revenues decreased as a result of a
decline in the price per kWh generated and a greater number of scheduled
refueling days and unscheduled outages in 1996 compared to 1995.
Revenues from diversified operations decreased $54 million for the nine-
month period ended September 30, 1996, compared to the same period in
1995, primarily due to Enterprises' sale of DALEN Corporation in June
1995.
Operating Expenses:
- ------------------
Operating expenses for the three- and nine-month periods ended September
30, 1996, increased $141 million and $440 million, respectively, compared
to the same periods in 1995. The increases for the three- and nine-month
periods ended September 30, 1996, are primarily due to increases in
maintenance and other operating expenses for distribution and customer-
related services and a charge of $182 million for contingencies related
to gas transportation commitments and the Accord. (See Gas Industry
Restructuring.) Additionally, expenses for the nine-month period ended
September 30, 1996, increased due to the settlement of outstanding
litigation and the termination of certain QF contracts.
Liquidity and Capital Resources
- -------------------------------
Sources and Uses of Capital:
- ---------------------------
The Company's capital requirements are funded from cash provided by
operations and, to the extent necessary, external financing. The
Company's policy is to finance its assets with a capital structure that
minimizes financing costs, maintains financial flexibility and complies
with regulatory guidelines. This policy ensures that the Company can
raise capital to meet its utility obligation to serve and its other
investment objectives.
During the nine-month period ended September 30, 1996, PG&E issued $169
million of common stock, primarily through its Dividend Reinvestment Plan
and Savings Fund Plan. PG&E repurchased $242 million of its common stock
on the open market during the nine-month period ended September 30, 1996.
In May 1996, PG&E refinanced $988 million of variable and fixed interest
rate pollution control revenue bonds with variable interest rate
pollution control revenue bonds. In addition, the Company used its cash
balances to reduce short-term borrowings by $830 million during the nine-
month period ended September 30, 1996.
In July 1996, the Company completed its acquisition of Queensland State
Gas Pipeline, a 389-mile natural gas transportation system in the
Australian state of Queensland. The final purchase price was
approximately $133 million, financed by cash and long-term debt.
Environmental Remediation:
- -------------------------
The Company assesses, on an ongoing basis, measures that may need to be
taken to comply with laws and regulations related to hazardous materials
and hazardous waste compliance and remediation. At September 30, 1996,
the Company had accrued $169 million for hazardous waste remediation
costs at those sites where such costs are probable and quantifiable. The
costs may be as much as $386 million if, among other things, other
potentially responsible parties are not financially able to contribute to
these costs or further investigation indicates that the extent of
contamination or necessary remediation is greater than anticipated at
sites for which the Company is responsible. This upper limit of the
range of costs was estimated using assumptions less favorable to the
Company, among a range of reasonably possible outcomes. Costs may be
higher if the Company is found to be responsible for cleanup costs at
additional sites or identifiable possible outcomes change. The Company
had recorded a regulatory asset at September 30, 1996, of $139 million
for recovery of these costs in future rates. (See Note 5 of Notes to
Consolidated Financial Statements.)
Legal Matters:
- -------------
In the normal course of business, the Company is named as a party in a
number of claims and lawsuits. Substantially all of these are litigated
or settled with no material impact on either the Company's results of
operations or financial position. Significant litigation cases are
discussed in Note 5 of Notes to Consolidated Financial Statements.
PART II. OTHER INFORMATION
---------------------------
Item 5. Other Information
-----------------
A. Helms Pumped Storage Plant
The Helms Pumped Storage Plant (Helms) became commercially
operable in 1984, following delays due to a water conduit rupture
in 1982 and various start-up problems related to the plant's
generators. As a result of the damage caused by the rupture and
the delay in the operational date, Pacific Gas and Electric
Company (PG&E) incurred additional costs which were excluded from
rate base and lost revenues during the period while the plant was
under repair.
In October 1994, PG&E submitted for California Public Utilities
Commission (CPUC) approval a settlement with the Division of
Ratepayer Advocates (DRA) regarding the recovery of Helms costs
not then in rate base (excluding costs related to the conduit
rupture for which a reserve had already been established) and
prior-year revenue requirements related to these costs. The
settlement provides for recovery of approximately $98 million,
which represents substantially all of the remaining net
unrecovered costs and revenues. Under the settlement, PG&E
agreed not to seek recovery of the costs associated with the
water conduit rupture, estimated to be $72.4 million. PG&E had
taken a charge against earnings for such costs in 1990.
On September 4, 1996, the CPUC issued a final decision adopting
the settlement. The decision permits PG&E to recover
approximately $98 million in Helms costs Because PG&E's current
rate recovery already reflects the anticipated settlement,
adoption of the settlement will have no impact on rates. On
October 7, 1996, Toward Utility Rate Normalization (TURN), a
consumer advocacy group, filed a motion for reconsideration of
the CPUC's decision. The CPUC is not obligated to take any
action on the motion. However, if the CPUC does not act on the
motion within 60 days, TURN may consider the motion denied and
pursue an appeal to the California Supreme Court.
B. Ratios of Earnings to Fixed Charges and Ratios of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
PG&E's earnings to fixed charges ratio for the nine months ended
September 30, 1996 was 2.90. PG&E's earnings to combined fixed
charges and preferred stock dividends ratio for the nine months
ended September 30, 1996 was 2.70. Statements setting forth the
computation of the foregoing ratios are filed herewith as
Exhibits 12.1 and 12.2 to Registration Statement Nos. 33-62488,
33-64136 and 33-50707.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K during the third quarter of 1996 and
through the date hereof:
1. August 21, 1996
Item 5. Other Events
A. Gas Accord Settlement
2. September 9, 1996
Item 5. Other Events
A. Electric Industry Restructuring Legislation
B. CPUC Reform Legislation
C. California Public Utilities Commission Proceedings
1. Electric Industry Restructuring
a. Diablo Canyon/Rate Freeze Application
b. CTC Application
2. Cost of Capital
3. October 16, 1996
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. Common Stock Dividend Reduction
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
November 14, 1996
CHRISTOPHER P. JOHNS
By______________________________
CHRISTOPHER P. JOHNS
Vice President and Controller
EXHIBIT INDEX
Exhibit
Number Exhibit
- ------- ---------------------------------------
11 Computation of Earnings Per Common Share
12.1 Computation of Ratios of Earnings to Fixed Charges
12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
27 Financial Data Schedule
<TABLE>
EXHIBIT 11
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
(unaudited)
<CAPTION>
- ----------------------------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
-------------------- ----------------------
(in thousands, except per share amounts) 1996 1995 1996 1995
- ----------------------------------------------------------------------------------------------
<S>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN <C> <C> <C> <C>
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income $233,695 $377,593 $606,179 $1,111,800
Less: preferred dividend requirement and
redemption premium 8,279 15,901 24,835 44,889
-------- -------- -------- ----------
Net income for calculating EPS for
Statement of Consolidated Income $225,416 $361,692 $581,344 $1,066,911
======== ======== ======== ==========
Average common shares outstanding 411,759 421,578 413,738 426,064
======== ======== ======== ==========
EPS as shown in the Statement of
Consolidated Income $ .55 $ .85 $ 1.41 $ 2.50
======== ======== ======== ==========
PRIMARY EPS (1)
Net income $233,695 $377,593 $606,179 $1,111,800
Less: preferred dividend requirement and
redemption premium 8,279 15,901 24,835 44,889
-------- -------- -------- ----------
Net income for calculating primary EPS $225,416 $361,692 $581,344 $1,066,911
======== ======== ======== ==========
Average common shares outstanding 411,759 421,578 413,738 $ 426,064
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from
such exercise (at average market price) 4 179 10 117
-------- -------- -------- ----------
Average common shares outstanding as
adjusted 411,763 421,757 413,748 426,181
======== ======== ======== ==========
Primary EPS $ .55 $ .85 $ 1.41 $ 2.50
======== ======== ======== ==========
FULLY DILUTED EPS (1)
Net income $233,695 $377,593 $606,179 $1,111,800
Less: preferred dividend requirement and
redemption premium 8,279 15,901 24,835 44,889
-------- -------- -------- ----------
Net income for calculating fully diluted EPS $225,416 $361,692 $581,344 $1,066,911
======== ======== ======== ==========
Average common shares outstanding 411,759 421,578 413,738 426,064
Add exercise of options, reduced by the
number of shares that could have been
purchased with the proceeds from such
exercise (at the greater of average or
ending market price) 4 204 10 204
-------- -------- -------- ----------
Average common shares outstanding as
adjusted 411,763 421,782 413,748 426,268
======== ======== ======== ==========
Fully diluted EPS $ .55 $ .85 $ 1.41 $ 2.50
======== ======== ======== ==========
- ----------------------------------------------------------------------------------------------
<FN>
(1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K.
This presentation is not required by APB Opinion No. 15, because it results in dilution
of less than 3%.
</TABLE>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) 9/30/96 1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 606,179 $1,338,885 $1,007,450 $1,065,495 $1,170,581 $1,026,392
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
undistributed losses
(income) of less than
50% owned affiliates (3,024) 3,820 (2,764) 6,895 (3,349) 26,671
Income tax expense 376,186 895,289 836,767 901,890 895,126 851,534
Net fixed charges 515,450 715,975 730,965 821,166 802,198 776,682
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $1,494,791 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 435,781 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185
Interest on short-
term borrowings 58,788 83,024 77,295 87,819 61,182 77,760
Interest on capital
leases 2,640 2,735 1,758 1,737 1,737 1,737
Capitalized interest 487 957 2,660 46,055 6,511 6,107
Earnings required to
cover the preferred
stock dividend and
preferred security
distribution requirements
of majority owned
subsidiaries 18,565 3,306 - - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $ 516,261 $ 717,397 $ 733,625 $ 867,221 $ 808,709 $ 782,789
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 2.90 4.12 3.51 3.22 3.54 3.43
- ---------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing the Company's ratios of earnings to fixed charges, "earnings"
represent net income adjusted for the minority interest in losses of less than 100% owned
affiliates, the Company's equity in undistributed income or loss of less than 50% owned
affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges"
include interest on long-term and short-term borrowings (including a representative portion
of rental expense); amortization of bond premium, discount and expense; interest on capital
leases; pretax earnings required to cover the preferred stock dividend requirements of
majority owned subsidiaries; and after-tax earnings required to cover the preferred security
distribution requirements of majority owned subsidiaries.
</TABLE>
<TABLE>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) 9/30/96 1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 606,179 $1,338,885 $1,007,450 $1,065,495 $1,170,581 $1,026,392
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates (3,024) 3,820 (2,764) 6,895 (3,349) 26,671
Income tax expense 376,186 895,289 836,767 901,890 895,126 851,534
Net fixed charges 515,450 715,975 730,965 821,166 802,198 776,682
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $1,494,791 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 435,781 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185
Interest on short-
term borrowings 58,788 83,024 77,295 87,819 61,182 77,760
Interest on capital
leases 2,640 2,735 1,758 1,737 1,737 1,737
Capitalized interest 487 957 2,660 46,055 6,511 6,107
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned subsidiaries 18,565 3,306 - - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 516,261 717,397 733,625 867,221 808,709 782,789
---------- ---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 7,542 11,343 4,672 4,814 5,136 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 29,333 99,984 96,039 108,937 130,147 154,404
---------- ---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 36,875 111,327 100,711 113,751 135,283 159,540
---------- ---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 553,136 $ 828,724 $ 834,336 $ 980,972 $ 943,992 $ 942,329
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.70 3.56 3.08 2.85 3.03 2.85
- ---------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing the Company's ratios of earnings to combined fixed charges and
preferred stock dividends, "earnings" represent net income adjusted for the minority interest
in losses of less than 100% owned affiliates, the Company's equity in undistributed income
or loss of less than 50% owned affiliates, income taxes and fixed charges (excluding
capitalized interest). "Fixed charges" include interest on long-term debt and short-term
borrowings (including a representative portion of rental expense); amortization of bond
premium, discount and expense; interest on capital leases; pretax earnings required to cover
the preferred stock dividend requirements of majority owned subsidiaries; and the after-tax
earnings required to cover the preferred security distribution requirements of majority owned
subsidiaries. "Preferred stock dividends" represent the sum of requirements for preferred
stock dividends that are deductible for federal income tax purposes increased to an amount
representing pretax earnings which would be required to cover such dividend requirements.
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 18,809,197
<OTHER-PROPERTY-AND-INVEST> 1,927,966
<TOTAL-CURRENT-ASSETS> 2,370,353
<TOTAL-DEFERRED-CHARGES> 2,542,199
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 25,649,715
<COMMON> 2,051,994
<CAPITAL-SURPLUS-PAID-IN> 3,755,008
<RETAINED-EARNINGS> 2,687,020
<TOTAL-COMMON-STOCKHOLDERS-EQ> 8,494,022
437,500
402,056
<LONG-TERM-DEBT-NET> 7,965,248
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 254,178
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 8,096,711
<TOT-CAPITALIZATION-AND-LIAB> 25,649,715
<GROSS-OPERATING-REVENUE> 6,909,286
<INCOME-TAX-EXPENSE> 376,186
<OTHER-OPERATING-EXPENSES> 5,522,671
<TOTAL-OPERATING-EXPENSES> 5,522,671
<OPERATING-INCOME-LOSS> 1,386,615
<OTHER-INCOME-NET> 90,688
<INCOME-BEFORE-INTEREST-EXPEN> 1,477,303
<TOTAL-INTEREST-EXPENSE> 494,938
<NET-INCOME> 606,179
24,835
<EARNINGS-AVAILABLE-FOR-COMM> 581,344
<COMMON-STOCK-DIVIDENDS> 607,237
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 2,133,265
<EPS-PRIMARY> 1.41
<EPS-DILUTED> 1.41
</TABLE>
