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 March 31, 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
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(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 April 29, 1996
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Common Stock, $5 par value 416,718,710 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
Gas Reasonableness Proceedings.......... 11
PGT/PG&E Pipeline Expansion Project..... 12
Transportation Commitments.............. 12
Note 4: Diablo Canyon............................. 14
Note 5: Contingencies
Nuclear Insurance....................... 15
Environmental Remediation............... 15
Helms Pumped Storage Plant.............. 16
Legal Matters........................... 16
Note 6: Company Obligated Mandatorily
Redeemable Preferred Securities
of Subsidiary Trust Holding Solely
PG&E Subordinated Debentures.............. 18
Item 2. Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Electric Industry Restructuring.................... 19
Gas Industry Restructuring......................... 25
Holding Company Structure.......................... 26
Utility Revenue Matters............................ 26
Results of Operations.............................. 29
Earnings Per Common Share........................ 29
Common Stock Dividend............................ 30
Operating Revenues............................... 30
Operating Expenses............................... 30
Liquidity and Capital Resources
Sources of Capital............................... 31
Acquisition...................................... 31
Environmental Remediation........................ 31
Legal Matters.................................... 31
Other Matters
New Accounting Standard.......................... 32
Accounting for Decommissioning Expense........... 32
PART II. OTHER INFORMATION
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Item 1. Legal Proceedings
Diablo Canyon Environmental Litigation............. 33
California Attorney General Litigation............. 34
Norcen Litigation.................................. 34
Table of Contents (continued)
Page
----
Item 4. Submission of Matters to a Vote of
Security-Holders................................... 35
Item 5. Other Information
Pending Electric Reasonableness Issue.............. 36
Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends............ 37
Item 6. Exhibits and Reports on Form 8-K..................... 37
SIGNATURE...................................................... 39
PART 1. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
---------------------------------
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
Three months ended March 31,
---------------------------
(in thousands, except per share amounts) 1996 1995
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<S> <C> <C>
OPERATING REVENUES
Electric utility $1,648,602 $1,696,786
Gas utility 568,811 544,095
Diversified operations 31,355 67,366
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Total operating revenues 2,248,768 2,308,247
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OPERATING EXPENSES
Cost of electric energy 466,994 404,723
Cost of gas 188,137 103,563
Maintenance and other operating 456,474 421,954
Depreciation and decommissioning 302,947 352,183
Administrative and general 179,379 261,121
Workforce reduction costs - (18,195)
Property and other taxes 81,443 73,869
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Total operating expenses 1,675,374 1,599,218
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OPERATING INCOME 573,394 709,029
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OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 24,343 15,326
Allowance for equity funds used during construction 2,757 5,638
Other--net 5,682 (2,468)
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Total other income and (income deductions) 32,782 18,496
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INCOME BEFORE INTEREST EXPENSE 606,176 727,525
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INTEREST EXPENSE
Interest on long-term debt 153,167 162,149
Other interest charges 22,318 14,776
Allowance for borrowed funds used during construction (1,557) (2,876)
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Net interest expense 173,928 174,049
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PRETAX INCOME 432,248 553,476
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INCOME TAXES 171,544 224,789
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NET INCOME 260,704 328,687
Preferred dividend requirement and redemption premium 8,278 14,494
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EARNINGS AVAILABLE FOR COMMON STOCK $ 252,426 $ 314,193
========== ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 414,351 430,086
EARNINGS PER COMMON SHARE $.61 $.73
DIVIDENDS DECLARED PER COMMON SHARE $.49 $.49
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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>
- --------------------------------------------------------------------------------------------
March 31, December 31,
(in thousands) 1996 1995
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<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $17,741,094 $17,513,830
Diablo Canyon 6,669,967 6,646,853
Gas 7,788,397 7,732,681
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Total plant in service (at original cost) 32,199,458 31,893,364
Accumulated depreciation and decommissioning (13,635,412) (13,308,596)
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Net plant in service 18,564,046 18,584,768
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CONSTRUCTION WORK IN PROGRESS 243,666 333,263
OTHER NONCURRENT ASSETS
Nuclear decommissioning funds 799,359 769,829
Investments in nonregulated projects 899,234 869,674
Other assets 129,309 130,128
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Total other noncurrent assets 1,827,902 1,769,631
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CURRENT ASSETS
Cash and cash equivalents 989,526 734,295
Accounts receivable
Customers 929,851 1,238,549
Other 69,027 65,907
Allowance for uncollectible accounts (34,267) (35,520)
Regulatory balancing accounts receivable 888,756 746,344
Inventories
Materials and supplies 186,957 181,763
Gas stored underground 108,760 146,499
Fuel oil 30,853 40,756
Nuclear fuel 178,507 175,957
Prepayments 32,919 47,025
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Total current assets 3,380,889 3,341,575
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DEFERRED CHARGES
Income tax-related deferred charges 1,056,118 1,079,673
Diablo Canyon costs 378,003 382,445
Unamortized loss net of gain on reacquired debt 387,575 392,116
Workers' compensation and disability claims recoverable 291,960 297,266
Other 504,179 669,553
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Total deferred charges 2,617,835 2,821,053
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TOTAL ASSETS $26,634,338 $26,850,290
=========== ===========
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<FN>
(continued on next page)
</Table
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
March 31, December 31,
(in thousands) 1996 1995
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<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,073,473 $ 2,070,128
Additional paid-in capital 3,749,153 3,716,322
Reinvested earnings 2,836,255 2,812,683
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Total common stock equity 8,658,881 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 7,985,999 8,048,546
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Total capitalization 17,484,436 17,487,235
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OTHER NONCURRENT LIABILITIES
Customer advances for construction 140,005 146,191
Workers' compensation and disability claims 271,400 271,000
Other 724,704 815,960
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Total other noncurrent liabilities 1,136,109 1,233,151
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CURRENT LIABILITIES
Short-term borrowings 763,304 829,947
Long-term debt 230,342 304,204
Accounts payable
Trade creditors 298,489 413,972
Other 429,959 387,747
Accrued taxes 466,071 274,093
Deferred income taxes 226,106 227,782
Interest payable 158,032 70,179
Dividends payable 211,445 205,467
Other 407,716 504,973
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Total current liabilities 3,191,464 3,218,364
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DEFERRED CREDITS
Deferred income taxes 3,894,880 3,933,765
Deferred tax credits 391,848 393,255
Noncurrent balancing account liabilities 192,640 185,647
Other 342,961 398,873
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Total deferred credits 4,822,329 4,911,540
CONTINGENCIES (Notes 2, 3 and 5)
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TOTAL CAPITALIZATION AND LIABILITIES $26,634,338 $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>
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Three months ended March 31,
---------------------------
(in thousands) 1996 1995
- --------------------------------------------------------------------------------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 260,704 $ 328,687
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and decommissioning 302,947 352,183
Amortization 24,204 33,316
Deferred income taxes and tax credits--net (16,606) (65,603)
Allowance for equity funds used during construction (2,757) (5,638)
Other deferred charges 88,982 (17,450)
Other noncurrent liabilities (23,042) (6,396)
Noncurrent balancing account liabilities and
other deferred credits (48,919) (37,674)
Net effect of changes in operating assets
and liabilities
Accounts receivable 304,325 218,891
Regulatory balancing accounts receivable (142,412) 253,216
Inventories 42,448 36,611
Accounts payable (73,271) (37,477)
Accrued taxes 191,978 246,313
Other working capital 4,702 2,479
Other-net 17,880 45,827
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Net cash provided by operating activities 931,163 1,347,285
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CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (216,880) (197,051)
Allowance for borrowed funds used during construction (1,557) (2,876)
Investments in nonregulated projects (38,339) (34,640)
Other--net (20,189) (54,241)
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Net cash used by investing activities (276,965) (288,808)
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CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 57,657 66,871
Common stock repurchased (39,364) (110,316)
Long-term debt matured, redeemed or repurchased (137,343) (149,250)
Short-term debt redeemed--net (66,643) (382,246)
Dividends paid (211,576) (225,875)
Other--net (1,698) (1,820)
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Net cash used by financing activities (398,967) (802,636)
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NET CHANGE IN CASH AND CASH EQUIVALENTS 255,231 255,841
CASH AND CASH EQUIVALENTS AT JANUARY 1 734,295 136,900
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CASH AND CASH EQUIVALENTS AT MARCH 31 $ 989,526 $ 392,741
========= ==========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 73,402 $ 89,689
Income taxes 45,638 43,975
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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
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Electric Industry Restructuring: On December 20, 1995, the California
Public Utilities Commission (CPUC) issued a decision calling for the
restructuring of California's electric industry. The CPUC's goal is to
provide a structure that will ultimately allow California consumers to
choose among competing suppliers of electricity. In summary, the
decision would (1) simultaneously create a wholesale power pool, or
Exchange, and allow direct access for certain customers to contract
directly with electric generation providers beginning in 1998 with all
customers phased in within five years; (2) establish an Independent
System Operator (ISO) to manage and control the transmission system;
and (3) provide recovery of utilities' stranded costs (costs which are
above-market and could not be recovered under market-based pricing)
through a surcharge, or competition transition charge (CTC), to be
imposed on all customers. The decision, while effective immediately,
provided for a series of implementation filings to be made in order to
achieve the January 1998 start date for the restructured industry.
Under the restructuring decision, PG&E would continue to provide
distribution, generation and procurement functions for those customers
choosing to take bundled service, all of which would be regulated under
performance-based ratemaking. The decision requires PG&E to file
proposals to establish performance-based ratemaking for its generation
and distribution functions.
The CPUC concluded that market power issues associated with the
electric industry restructuring almost certainly mandate that the
investor-owned utilities (IOUs) divest themselves of a substantial
portion of their fossil fuel generation assets. Accordingly, the
decision required PG&E to file a plan to voluntarily divest at least 50
percent of its fossil fuel generation assets. In March 1996, PG&E
filed comments with the CPUC on divestiture of fossil fuel generation
assets, as discussed below.
The decision provides for the collection of transition costs through
the imposition of a non-bypassable CTC. Transition cost recovery would
not increase rates beyond the rate levels in effect as of January 1,
1996. A transition cost account would be established for each utility.
Transition costs associated with regulatory assets would be included in
the account as authorized by the CPUC. The account would be adjusted
annually for the difference between authorized revenues associated with
the generation assets and actual revenues earned in the market as well
as after a generation asset receives its market valuation. Valuation
of above-market generation assets would be completed by 2003. Utility
nonnuclear generation assets would be valued through sale, spin-off or
market appraisal.
Transition costs resulting from the operation of nuclear generation
facilities and electricity purchases under existing wholesale and
qualifying facility (QF) contracts would also be recorded in this
account. Transition costs for these resources would be calculated
annually over the terms of the contracts or until the authorized
transition cost recovery has been completed. Except for existing QF
generation contracts with contractual payments beyond 2003, all
transition costs would be collected by 2005.
With respect to recovery of costs associated with PG&E's Diablo Canyon
Nuclear Power Plant (Diablo Canyon) and the Diablo Canyon rate case
settlement as modified in 1995 (Diablo Settlement), the decision
confirms that the CPUC will continue to honor regulatory commitments
regarding the recovery of nuclear generation costs. Under the CPUC
restructuring decision, Diablo Canyon transition costs would be
calculated over the term of the Diablo Settlement. The decision
required PG&E to file a proposal for pricing Diablo Canyon generation
at market prices by 2003 and for completing recovery of Diablo Canyon
CTC by 2005 while assuring no overall rate increase over January 1,
1996, levels. If PG&E retains ownership of Diablo Canyon,
decommissioning costs would also be included in the transition cost
account. In March 1996, PG&E filed an application with the CPUC to
modify the Diablo Settlement and adopt a customer electric rate freeze,
as discussed below.
Recent Developments in the Electric Industry Restructuring: As
directed by the CPUC decision, PG&E has made filings with the CPUC on
various aspects of the electric industry restructuring. In March 1996,
PG&E filed comments indicating that it is willing to proceed with
voluntary divestiture of at least 50 percent of its fossil fuel
generation assets, as long as CTC recovery is satisfactorily resolved.
PG&E also filed comments 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.
Also in March 1996, PG&E filed an application with the CPUC seeking
approval to modify the Diablo Settlement, as discussed in Note 4,
contingent upon the adoption of a five-year electric rate freeze,
effective January 1, 1997. The application would reduce the amount of
Diablo Canyon transition costs by over $3.7 billion (net present value)
compared to transition costs that would arise under existing Diablo
Canyon prices, while recovering remaining Diablo Canyon and other
uneconomic utility generation assets by no later than the end of 2001.
The filing would accelerate PG&E's recovery of utility generation-
related transition costs caused by industry restructuring without
raising customer rates. PG&E's application would result in the
termination of the Diablo Settlement by the end of 2001, so that Diablo
Canyon generation may be priced at market levels consistent with the
goals of the CPUC restructuring decision.
PG&E proposes that the current pricing of Diablo Canyon generation, as
set forth in the Diablo Settlement, be replaced by a new pricing
arrangement. Under this approach, the current Diablo Canyon fixed
price would be replaced by a sunk cost revenue requirement consisting
of PG&E's remaining sunk costs in Diablo Canyon as of December 31,
1996, depreciated over a five-year period and subject to a reduced
return on common equity equal to 6.77 percent. Sunk costs include net
plant, working capital and regulatory assets, all net of deferred
taxes. The sunk cost revenue requirement would be recovered without
reference to Diablo Canyon's performance, unless the plant were shut
down for nine months or more.
The escalating component of current Diablo Canyon prices would be
replaced by a performance-based Incremental Cost Incentive Price (ICIP)
for recovery of Diablo Canyon's variable costs and future capital
additions. Under the ICIP, the variable costs and incremental capital
additions are recovered under a pre-set price per kilowatt-hour (kWh)
of plant output based on an initial forecast of such costs and output.
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 period of years following permanent plant closure.
PG&E's continued recovery of the sunk cost revenue requirement, if
Diablo Canyon is shut down for nine months or more prior to such time
as transition costs are fully recovered, would be subject to CPUC
evaluation. After such time as transition costs are fully recovered,
there would be no restrictions on Diablo Canyon's operations or to
which customers it could sell and at what prices, terms and conditions,
but 50 percent of any after-tax earnings available for common equity
after such time would be allocated to ratepayers.
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. At PG&E's option, recovery of
estimated decommissioning costs could be accelerated under the customer
electric rate freeze over the same depreciation period as Diablo
Canyon's sunk costs.
In conjunction with these modifications to the Diablo Settlement,
PG&E's application proposes that the CPUC adopt a customer electric
rate freeze at 1996 levels through the end of 2001, in order to permit
PG&E to accelerate capital recovery of its other utility generation and
associated regulatory assets through 2001. PG&E would be at risk for
completing recovery of PG&E's above-market utility generation-related
investments, including Diablo Canyon, and related regulatory assets by
the end of 2001.
PG&E indicated that adoption of its customer electric rate freeze
proposal is linked inextricably with the modified Diablo Canyon pricing
proposal. In the event that the CPUC is unable to adopt the proposed
rate freeze, PG&E would withdraw its proposal to price Diablo Canyon
generation and instead would propose an alternative modification of
Diablo Canyon pricing.
In April 1996, PG&E, San Diego Gas and Electric Company and Southern
California Edison Company filed joint ISO and Exchange applications
with the Federal Energy Regulatory Commission (FERC) and CPUC. These
applications request authorization to transfer operational control (but
not ownership) of certain jurisdictional transmission facilities to the
ISO and to sell electric energy at market-based rates using the
Exchange. The ISO would manage the dispatch of electric generation,
manage access to the transmission system and assure safe, reliable
operation of the state's power grid. The Exchange would conduct a
daily auction among buyers and sellers to determine the spot market
price for power. PG&E and the other utilities also filed a request for
a declaratory order from the FERC confirming the utilities' designation
of transmission facilities to be transferred to ISO control, and
confirming the states' jurisdiction over local distribution facilities
for rate and transition cost collection purposes. PG&E intends to file
an application with the CPUC in May 1996 seeking funding for costs
associated with the establishment of the ISO and Exchange.
In April 1996, the CPUC granted PG&E's emergency motion to establish an
interim CTC procedure applicable to certain departing electric retail
customers. This rate procedure will remain in effect until the CPUC
adopts and implements a final CTC mechanism, which is expected to be
effective January 1998. At that time, amounts paid on an interim basis
will be subject to true-up to reflect the CPUC's final CTC methodology
and allocation of CTC to customer classes. Pursuant to the CPUC's
decision establishing an interim CTC procedure, interested parties
engaged in a collaboration in an attempt to set an interim CTC level
consistent with the principles set forth in the CPUC decision. Since
no consensus was reached among the parties, the unresolved issues will
be referred to a CPUC administrative law judge (ALJ) to prepare a
recommended decision for CPUC approval. The CPUC is expected to
establish the interim CTC in 1996.
Also 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 how utilities use their own systems. 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.
In the coming months, PG&E will be making additional filings with the
CPUC and FERC on other aspects of the electric industry restructuring,
as directed by the December 20, 1995, decision.
Financial Impact of the Electric Industry Restructuring: In December
1994, in response to one of the proceedings leading to the CPUC
electric industry restructuring decision, PG&E estimated the revenue
requirements of its owned generation assets and power purchase
obligations to be above market by $3 billion and $11 billion (net
present value) at assumed market prices of $.040 and $.032 per kWh,
respectively. These market prices were used to provide a range of
possible transition costs and do not represent a forecast of expected
market prices. Market prices could be less than $.032 per kWh. The
above-market estimates filed in December 1994 were determined by
comparing future revenue requirements of generation assets and power
purchase obligations, over a 20-year and 30-year period, respectively,
with revenues computed at assumed market prices. Diablo Canyon was
included in the revenue requirement calculation using the pricing
included in the Diablo Settlement. (See Note 4.) The revenue
requirements for Diablo Canyon and all PG&E-owned generation assets
included a return on investment. The actual amounts of above-market
revenue requirements may differ materially from those indicated above
and will depend on the final regulations and the actual market prices
of electricity or a definitive market valuation.
Based on the pricing included in the Diablo Settlement, the net present
values of above-market revenue requirements for Diablo Canyon included
in the December 1994 estimates were $4 billion and $6 billion at
assumed market prices of $.040 and $.032 per kWh, respectively. Also
based on the pricing included in the Diablo Settlement, the net present
value of above-market revenue requirements for Diablo Canyon is
estimated to be $10 billion at a market price of $.025 per kWh, which
reflects PG&E's current estimate of the market price beginning in 1997.
The CPUC electric industry restructuring decision establishes an
account to track the accumulation of transition costs and their
recovery. While the decision provides an opportunity for recovery of
all above-market costs, actual recovery of the CTC will be limited to
an amount that does not increase the customers' aggregate rates above
those in effect on January 1, 1996. Recent CPUC decisions effective on
January 1, 1996, including PG&E's 1996 General Rate Case (GRC), have
resulted in an average electric system rate of $.099 per kWh. PG&E's
ability to recover its transition costs will be dependent on achieving
overall reductions in costs such that it can recover its ongoing
operating costs, capital costs and transition costs at the 1996 rate
level and on continuing to collect CTC for the duration of the recovery
period.
As a result of applying the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," PG&E has accumulated approximately $2.5
billion of electric regulatory assets, including balancing accounts, at
March 31, 1996. The regulatory assets attributable to electric
generation, excluding balancing accounts of $173 million which are
expected to be recovered in the near term, were approximately $1.4
billion at March 31, 1996. When generation rates are no longer based
on cost of service, as ultimately contemplated under the decision, PG&E
will discontinue application of SFAS No. 71 for that portion of its
business. However, PG&E expects to recover its generation regulatory
assets as transition costs through the CTC and does not expect a
material loss from the discontinuance of SFAS No. 71. PG&E's
transmission and distribution businesses are expected to remain under
the provisions of SFAS No. 71.
In addition, the adoption of SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of," in 1996 requires that regulatory assets continue to be
probable of recovery in rates. In the event that this criterion can no
longer be met, whether due to changing regulation or PG&E's inability
to collect these costs, applicable portions of any regulatory assets
would be written off. The transition cost account will be a regulatory
asset also subject to the criteria of SFAS No. 121.
The CPUC restructuring decision provides a structure for full recovery
of PG&E's generation assets and costs through market prices and the
CTC. The proposed modification to the Diablo Settlement offers
substantial reductions in post-2001 performance-based revenues in
exchange for a commitment to freeze customer electric rates through
2001 to allow accelerated collection of utility generation-related CTC.
If accepted, the proposed modification will significantly reduce the
level of PG&E's CTC and earnings by reducing the common equity returns
on the Diablo Canyon plant investment to 6.77 percent and accelerating
the capital recovery of the plant and other utility generation-related
assets. If the proposal to freeze customer electric rates is adopted,
PG&E will depreciate and recover the Diablo Canyon plant balance at
January 1997 over five years rather than the current recovery period
through 2016. In addition, the proposal would also limit recovery of
most utility generation-related CTC to amounts collected through 2001.
As of March 31, 1996, the net investment in Diablo Canyon and the
remaining PG&E-owned generation assets, including an allocation of
common plant, was approximately $4.8 billion and $3.0 billion,
respectively, and regulatory assets attributable to electric generation
(excluding balancing accounts expected to be recovered in the near
term) were approximately $1.4 billion. Because of the expected
transition cost recovery as provided in the decision, PG&E does not
anticipate a material impairment loss on its investment in generation
assets due to electric industry restructuring. However, should final
implementing regulations differ significantly from the CPUC decision or
should full recovery of generation assets and obligations not be
achieved due to changing costs or limitations imposed by the market, a
material loss could occur.
The Company cannot predict the ultimate outcome of the ongoing changes
that are taking place in the electric utility industry or predict
whether such outcome will have a material impact on its financial
position or results of operations.
NOTE 3: Natural Gas Matters
- ---------------------------
Gas Reasonableness Proceedings:
- ------------------------------
Recovery of gas costs through PG&E's regulatory balancing account
mechanisms is subject to a CPUC determination that such costs were
reasonable. Under the current regulatory framework, annual
reasonableness proceedings are conducted by the CPUC on a historic
calendar year basis.
In 1994, the CPUC issued a decision which ordered a disallowance of
approximately $90 million of gas costs plus accrued interest of
approximately $25 million through 1993 for PG&E's Canadian gas
procurement activities from 1988 through 1990. In March 1996, PG&E
refunded $53 million of the ordered disallowance to ratepayers pursuant
to a CPUC decision in December 1995 on PG&E's Biennial Cost Allocation
proceeding. PG&E has filed a lawsuit in a federal district court
challenging the CPUC decision on Canadian gas costs. In 1995, the
federal court denied a motion filed by the CPUC to dismiss the lawsuit.
A number of other reasonableness issues related to PG&E's gas
procurement practices, transportation capacity commitments and supply
operations for periods dating from 1988 to 1994 are still under review
by the CPUC. The DRA had recommended disallowances of approximately
$79 million and a penalty of $50 million and indicated that it was
considering additional recommendations for pending issues. PG&E and
the CPUC's Division Ratepayer Advocates (DRA) have signed a settlement
agreement to resolve these issues for a $67 million refund by PG&E.
As of March 31, 1996, PG&E has accrued approximately $150 million for
the CPUC decision and issues covered by the settlement agreement
described above. The Company believes the ultimate outcome of these
matters will not have a material impact on its financial position or
results of operations.
Settlement of certain other unresolved gas issues is being negotiated
as part of the Gas Accord negotiations discussed below.
PGT/PG&E Pipeline Expansion Project (Pipeline Expansion):
- --------------------------------------------------------
In November 1993, the Company placed in service an expansion of its
natural gas transmission system from the Canadian border into
California. The Pipeline Expansion provides additional firm
transportation capacity to Northern and Southern California and the
Pacific Northwest. The total cost of construction is estimated to be
approximately $1.7 billion; $810 million for the PG&E or California
portion (PG&E Pipeline Expansion) and $852 million for the Pacific Gas
Transmission Company (PGT) or interstate portion.
PG&E has filed an application with the CPUC requesting that capital and
operating costs for the PG&E Pipeline Expansion be found reasonable.
In that CPUC proceeding, the DRA recommended that a minimum of $100
million in capital costs be disallowed for recovery in rates while two
intervenors jointly recommended a $223 million disallowance or
reallocation of costs among customers. An order issued by an ALJ has
also reopened the 1993 PG&E Pipeline Expansion Rate Case to allow
reconsideration of issues regarding the decision to construct the PG&E
Pipeline Expansion.
If the CPUC were to reverse its previous decision finding PG&E was
reasonable in constructing the PG&E Pipeline Expansion, the ultimate
outcome could have an impact on PG&E's ability to recover its cost for
unused capacity on other pipelines as well as on its own intrastate
facilities.
In January 1996, an ALJ ordered consolidation of the market impact
phase of the PG&E Pipeline Expansion reasonableness proceeding and the
Interstate Transition Cost Surcharge (ITCS) proceeding discussed below.
For the interstate portion of the Pipeline Expansion, PGT included $832
million of capital costs, representing such costs incurred through July
1994, in its 1994 GRC filing with the FERC. No parties contested these
costs and the parties have since filed a settlement of that rate case
with the FERC for approval.
Decisions in these proceedings are expected in 1996. Revenues are
currently being collected under interim rates approved by the FERC and
the CPUC, subject to adjustment.
Transportation Commitments:
- --------------------------
PG&E has gas transportation service agreements with various Canadian
and interstate pipeline companies. These agreements include provisions
for fixed demand charges for reserving firm capacity on the pipelines.
The total demand charges that PG&E will pay each year may change due to
changes in tariff rates and may be offset to the extent PG&E can broker
or permanently assign any unused capacity.
The following table summarizes the approximate capacity held by PG&E on
various pipelines (excluding PGT) and the related annual demand charges
as of March 31, 1996:
Total
Firm Capacity Annual Demand
Pipeline Held Charges Contract
Company (MMcf/d) (in millions) Expiration
- ---------------------- ------------- ------------- ----------
El Paso 1,140 $163 Dec. 1997
Transwestern 200 $ 28 Mar. 2007
NOVA 600 $ 20 Oct. 2001
ANG 600 $ 13 Oct. 2005
As a result of regulatory changes, PG&E no longer procures gas for its
industrial and large commercial (noncore) customers resulting in a
decrease in PG&E's need for firm transportation capacity for its gas
purchases. PG&E continues to procure gas for its residential and
smaller commercial (core) customers and noncore customers who choose
bundled service (core subscription customers). In order to service
these customers, PG&E holds approximately 600 million cubic feet per
day (MMcf/d) of firm capacity for its core and core subscription
customers on each of the pipelines owned by El Paso Natural Gas Company
(El Paso), NOVA Corporation of Alberta (NOVA) and Alberta Natural Gas
Company Ltd (ANG).
PG&E is continuing its efforts to broker or assign any remaining unused
capacity including that held for its core and core subscription
customers when such capacity is not being used. Due to relatively low
demand for Southwest pipeline capacity, PG&E cannot predict the volume
or price of the capacity on El Paso and Transwestern Pipeline Company
(Transwestern) that will be brokered or assigned.
Substantially all demand charges incurred by PG&E for pipeline
capacity, including charges for capacity formerly used to service
noncore customers which cannot be brokered or brokered at a discount,
are eligible for rate recovery, subject to a reasonableness review.
However, certain groups, including the DRA and intervenors, have
challenged the recovery of certain demand charges.
In December 1995, the CPUC issued a decision on the reasonableness of
PG&E's 1992 operations concluding that it was unreasonable for PG&E to
subscribe for transportation capacity with Transwestern. The decision
concluded that PG&E was unable to prove the benefits of such capacity
during 1992 and denied recovery of the $18 million of Transwestern
charges for that year. The decision further orders that costs for the
capacity in subsequent years of the contract, which expires in 2007, be
disallowed unless PG&E can demonstrate that the benefits of the
commitment outweigh the costs. PG&E is seeking rehearing of this
decision.
The recovery of demand charges associated with capacity which was
formerly used to serve PG&E's noncore customers will be decided by the
CPUC in the ITCS proceeding. Pending a final decision in the ITCS
proceeding, the CPUC has approved collection in rates of approximately
one-half of the demand charges for unbrokered or discounted El Paso and
PGT capacity which was formerly used to serve PG&E's noncore customers,
subject to refund.
In October 1995, PG&E presented a proposal, called the Gas Accord, to
numerous parties active in the California gas marketplace, in an effort
to restructure the California gas market. As part of the Gas Accord
negotiations, PG&E is pursuing the resolution of existing regulatory
issues pending in separate CPUC proceedings. Regulatory issues being
negotiated as part of the Gas Accord include PG&E's capacity
commitments with Transwestern, recovery of the costs for unbrokered
capacity commitments under the ITCS mechanism and the reasonableness
proceedings for the PG&E Pipeline Expansion.
Based on the current status of the Gas Accord negotiations and
regulatory proceedings, the Company believes the ultimate resolution of
past and future Transwestern costs, the ITCS proceeding and the PG&E
Pipeline Expansion proceedings, either through settlement negotiations
or ongoing proceedings, 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 cents, 10.0
cents, 9.5 cents 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.
The modification provides that the difference between PG&E's revenue
requirements under the original Diablo Settlement prices and the
modified prices be applied to PG&E's energy cost balancing account
until the undercollection in that account as of December 31, 1995, is
fully amortized. 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
for both pricing Diablo Canyon generation at market prices and
completing recovery of Diablo Canyon CTC by the end of 2001 while
assuring no overall rate increase over January 1, 1996, levels. PG&E
proposes to accelerate recovery of the undepreciated portion of
Diablo Canyon, at a significantly reduced return of 6.77 percent, and
to include performance-based prices for recovery of variable costs
and incremental capital additions. In addition to modifying the
pricing provisions of the existing Diablo Settlement, PG&E's proposal
would eliminate or replace certain payment provisions and change the
Diablo Settlement termination date from 2016 to December 31, 2001.
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 $26 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; federal Superfund law) or the California
Hazardous Substance Account Act (California Superfund law). 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 has an accrued
liability at March 31, 1996, of $126 million for hazardous waste
remediation costs at those sites where such costs are probable and
quantifiable. The costs may be as much as $292 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. 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 $719 million at March 31, 1996.
The net investment is comprised of the pumped storage facility
(including regulatory assets of $50 million), common plant and
dedicated transmission plant. As part of the 1996 GRC decision in
December 1995, the CPUC directed PG&E to perform a cost-effectiveness
study of Helms, to be submitted in July 1996. The study will consider
changes in rate recovery for the plant which will include, among other
things, the option of retirement with recovery of the investment
without a return over a four-year period.
PG&E is currently unable to predict whether there will be a change in
rate recovery resulting from the study. 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:
- -------------
Hinkley Litigation: In 1993, a complaint was filed in a state superior
court on behalf of individuals seeking recovery of an unspecified
amount of damages for personal injuries and property damage allegedly
suffered as a result of exposure to chromium near PG&E's Hinkley
Compressor Station, as well as punitive damages. The original
complaint has been amended, and additional complaints have been filed
to include additional plaintiffs.
The plaintiffs contend that PG&E discharged chromium-contaminated
wastewater into unlined ponds to avoid costly alternatives, which led
to chromium percolating into the groundwater of surrounding property.
PG&E has reached an agreement with plaintiffs pursuant to which those
plaintiffs' actions will be submitted to binding arbitration for
resolution of issues concerning the cause and extent of any damages
suffered by plaintiffs as a result of the alleged chromium
contamination. Under the terms of the agreement, PG&E will pay an
aggregate amount of no more than $400 million in settlement of such
plaintiffs' claims. In turn, those plaintiffs, and their attorneys,
agree to indemnify PG&E against any additional losses PG&E may incur
with respect to related claims pursued by the identified plaintiffs who
do not agree to this settlement or by other third parties who may be
sued by the plaintiffs in connection with the alleged chromium
contamination.
As of March 31, 1996, PG&E has paid $50 million to escrow and recorded
an additional $150 million reserve against any future potential
liability in this case. The Company believes the ultimate outcome of
this matter will not have a material adverse impact on its financial
position or results of operations.
Cities Franchise Fees Litigation: 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 granted PG&E's
motions for summary judgment against certain plaintiffs effectively
eliminating a major portion of the class action. The Court's rulings
do not resolve the case completely.
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 $33 million as of
March 31, 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 cities 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).
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% 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.
The following discussion includes some forward looking information.
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.
Electric Industry Restructuring:
- -------------------------------
On December 20, 1995, the CPUC, by a three to two vote, issued a
decision calling for the restructuring of California's electric
industry. The restructuring contemplated in the decision would (1)
simultaneously create a wholesale power pool, or Exchange, and allow
direct access for certain customers to contract directly with electric
generation providers beginning, at the latest, on January 1, 1998, with
all customers phased into direct access within five years; (2)
establish an Independent System Operator (ISO) to manage and control
the transmission system; and (3) provide recovery of utilities'
stranded costs through a non-bypassable surcharge, or competition
transition charge (CTC), to be imposed on all customers taking retail
electric service as of or after December 20, 1995. The decision, while
effective immediately, sets out an ambitious schedule for various
implementation filings and comments over the period ending in October
1996. See Note 2 of Notes to Consolidated Financial Statements for
further discussion of the electric industry restructuring.
Recent Developments in the Electric Industry Restructuring: As
directed by the CPUC decision, PG&E has made filings with the CPUC on
various aspects of the electric industry restructuring. In March 1996,
PG&E filed comments indicating that it is willing to proceed with
voluntary divestiture of at least 50 percent of its fossil fuel
generation assets, as long as CTC recovery is satisfactorily resolved.
Options for divestiture include creation of a new unaffiliated
corporate entity to hold the assets, sale on the open market,
negotiation with individual potential buyers in special circumstances,
leasing facilities and/or sale to employees through an employee stock
ownership plan. PG&E will also evaluate the economic feasibility and
desirability of divesting additional nonnuclear generating assets.
PG&E is currently evaluating the marketplace, including identifying
plants that might be divested, and identifying the form divestiture
might take and when it might occur.
In March 1996, PG&E also filed comments 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. In its comments, PG&E indicated for the time being it sees
no obvious benefits from separating its generation, transmission and
distribution functions into separate corporate subsidiaries. PG&E
believes that the operational and functional separation which exists by
virtue of its business unit structure, combined with the self-dealing
restraints imposed by the CPUC decision, provide sufficient safeguards
to prevent cross-subsidization and self-dealing. However, PG&E
believes it may be appropriate in the future to separate out any
generation it retains and that such separation would be consistent with
the holding company structure it proposed in a filing with the CPUC in
October 1995.
Also in March 1996, PG&E filed an application with the CPUC seeking
approval to modify the existing Diablo Canyon Nuclear Power Plant
(Diablo Canyon) rate case settlement (Diablo Settlement) contingent
upon the adoption of a five-year electric rate freeze, effective
January 1, 1997. The application would reduce the amount of Diablo
Canyon transition costs by over $3.7 billion (net present value)
compared to transition costs that would arise under existing Diablo
Canyon prices, while recovering remaining Diablo Canyon and other
uneconomic utility generation assets by no later than the end of 2001.
The filing would accelerate PG&E's recovery of utility generation-
related transition costs caused by industry restructuring without
raising customer rates. PG&E's application would result in the
termination of the Diablo Settlement by the end of 2001, so that Diablo
Canyon generation may be priced at market levels consistent with the
goals of the CPUC restructuring decision.
PG&E proposes that the current pricing of Diablo Canyon generation, as
set forth in the Diablo Settlement, be replaced by a new pricing
arrangement. Under this approach, the current Diablo Canyon fixed
price would be replaced by a sunk cost revenue requirement consisting
of PG&E's remaining sunk costs in Diablo Canyon as of December 31,
1996, depreciated over a five-year period and subject to a reduced
return on common equity equal to 6.77 percent. Sunk costs include net
plant, working capital and regulatory assets, all net of deferred
taxes. The sunk cost revenue requirement would be recovered without
reference to Diablo Canyon's performance, unless the plant were shut
down for nine months or more.
The escalating component of current Diablo Canyon prices would be
replaced by a performance-based Incremental Cost Incentive Price (ICIP)
for recovery of Diablo Canyon's variable costs and future capital
additions. Under the ICIP, the variable costs and incremental capital
additions are recovered under a pre-set price per kilowatt-hour (kWh)
of plant output based on an initial forecast of such costs and output.
In its filing, the Company estimated such variable costs and
incremental capital additions would be $552 million in 1997.
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 period of years following permanent plant closure.
PG&E's continued recovery of the sunk cost revenue requirement, if
Diablo Canyon is shut down for nine months or more prior to such time
as transition costs are fully recovered, would be subject to CPUC
evaluation. After such time as transition costs are fully recovered,
there would be no restrictions on Diablo Canyon's operations or to
which customers it could sell and at what prices, terms and conditions,
but 50 percent of any after-tax earnings available for common equity
after such time would be allocated to ratepayers.
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. At PG&E's option, recovery of
estimated decommissioning costs could be accelerated under the customer
electric rate freeze over the same depreciation period as Diablo
Canyon's sunk costs.
In conjunction with these modifications to the Diablo Settlement,
PG&E's application proposes that the CPUC adopt a customer electric
rate freeze at 1996 levels through the end of 2001, in order to permit
PG&E to accelerate capital recovery of its other utility generation and
associated regulatory assets through 2001. PG&E would be at risk for
completing recovery of PG&E's above-market utility generation-related
investments, including Diablo Canyon, and related regulatory assets by
the end of 2001.
PG&E indicated that adoption of its customer electric rate freeze
proposal is linked inextricably with the modified Diablo Canyon pricing
proposal. In the event that the CPUC is unable to adopt the proposed
rate freeze, PG&E would withdraw its proposal to price Diablo Canyon
generation and instead would propose an alternative modification of
Diablo Canyon pricing.
In April 1996, PG&E, San Diego Gas and Electric Company and Southern
California Edison Company filed joint ISO and Exchange applications
with the FERC and CPUC. These applications request authorization to
transfer operational control (but not ownership) of certain
jurisdictional transmission facilities to the ISO and to sell electric
energy at market-based rates using the Exchange. The ISO would manage
the dispatch of electric generation, manage access to the transmission
system and assure safe, reliable operation of the state's power grid.
The Exchange would conduct a daily auction among buyers and sellers to
determine the spot market price for power. PG&E and the other
utilities also filed a request for a declaratory order from the FERC
confirming the utilities' designation of transmission facilities to be
transferred to ISO control and confirming the states' jurisdiction over
local distribution facilities for rate and transition cost collection
purposes. PG&E intends to file an application with the CPUC in May
1996 seeking funding for costs associated with the establishment of the
ISO and Exchange.
In April 1996, the CPUC granted PG&E's emergency motion to establish an
interim CTC procedure applicable to certain departing electric retail
customers. This rate procedure will remain in effect until the CPUC
adopts and implements a final CTC mechanism, which is expected to be
effective January 1998. At that time, amounts paid on an interim basis
will be subject to true-up to reflect the CPUC's final CTC methodology
and allocation of CTC to customer classes. Pursuant to the CPUC's
decision establishing an interim CTC procedure, interested parties
engaged in a collaboration in an attempt to set an interim CTC level
consistent with the principles set forth in the CPUC decision. Since
no consensus was reached among the parties, the unresolved issues will
be referred to an administrative law judge to prepare a recommended
decision for CPUC approval. The CPUC is expected to establish the
interim CTC in 1996.
Also in April 1996, the FERC issued Order 888. That order requires all
utilities under the FERC's jurisdiction to file a wholesale
transmission service tariff intended to provide wholesale open access
to utility transmission systems on terms that are comparable to how
utilities use their own systems. In the same order, 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.
In the coming months, PG&E will be making additional filings with the
CPUC and FERC on other aspects of the electric industry restructuring,
as directed by the December 20, 1995, decision.
Financial Impact of the Electric Industry Restructuring: In December
1994, in response to one of the proceedings leading to the CPUC
electric industry restructuring decision, PG&E estimated the revenue
requirements of its owned generation assets and power purchase
obligations to be above market by $3 billion and $11 billion (net
present value) at assumed market prices of $.040 and $.032 per kWh,
respectively. These market prices were used to provide a range of
possible transition costs and do not represent a forecast of expected
market prices. Market prices could be less than $.032 per kWh. The
above-market estimates filed in December 1994 were determined by
comparing future revenue requirements of generation assets and power
purchase obligations, over a 20-year and 30-year period, respectively,
with revenues computed at assumed market prices. Diablo Canyon was
included in the revenue requirement calculation using the pricing
included in the Diablo Settlement. (See Note 4 to Notes to
Consolidated Financial Statements.) The revenue requirements for
Diablo Canyon and all PG&E-owned generation assets included a return on
investment. The actual amounts of above-market revenue requirements
may differ materially from those indicated above and will depend on the
final regulations and the actual market prices of electricity or a
definitive market valuation.
Based on the pricing included in the Diablo Settlement, the net present
values of above-market revenue requirements for Diablo Canyon included
in the December 1994 estimates were $4 billion and $6 billion at
assumed market prices of $.040 and $.032 per kWh, respectively. Also
based on the pricing included in the Diablo Settlement, the net present
value of above-market revenue requirements for Diablo Canyon is
estimated to be $10 billion at a market price of $.025 per kWh, which
reflects PG&E's current estimate of the market price beginning in 1997.
The CPUC electric industry restructuring decision establishes an
account to track the accumulation of transition costs and their
recovery. While the decision provides an opportunity for recovery of
all above-market costs, actual recovery of the CTC will be limited to
an amount that does not increase the customers' aggregate rates above
those in effect on January 1, 1996. Recent CPUC decisions effective on
January 1, 1996, including PG&E's 1996 General Rate Case (GRC), have
resulted in an average electric system rate of $.099 cents per kWh.
PG&E's ability to recover its transition costs will be dependent on
achieving overall reductions in costs such that it can recover its
ongoing operating costs, capital costs and transition costs at the 1996
rate level and on continuing to collect CTC for the duration of the
recovery period.
As a result of applying the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," PG&E has accumulated approximately $2.5
billion of electric regulatory assets, including balancing accounts, at
March 31, 1996. The regulatory assets attributable to electric
generation, excluding balancing accounts of $173 million which are
expected to be recovered in the near term, were approximately $1.4
billion at March 31, 1996. When generation rates are no longer based
on cost of service, as ultimately contemplated under the decision, PG&E
will discontinue application of SFAS No. 71 for that portion of its
business. However, PG&E expects to recover its generation regulatory
assets as transition costs through the CTC and does not expect a
material loss from the discontinuance of SFAS No. 71. PG&E's
transmission and distribution businesses are expected to remain under
the provisions of SFAS No. 71.
In addition, the adoption of SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of," in 1996 requires that regulatory assets continue to be
probable of recovery in rates. In the event that this criterion can no
longer be met, whether due to changing regulation or PG&E's inability
to collect these costs, applicable portions of any regulatory assets
would be written off. The transition cost account will be a regulatory
asset also subject to the criteria of SFAS No. 121.
The CPUC restructuring decision provides a structure for full recovery
of PG&E's generation assets and costs through market prices and the
CTC. The proposed modification to the Diablo Settlement offers
substantial reductions in post-2001 performance-based revenues in
exchange for a commitment to freeze customer electric rates through
2001 to allow accelerated collection of utility generation-related CTC.
If accepted, the proposed modification will significantly reduce the
level of PG&E's CTC and earnings by reducing the common equity returns
on the Diablo Canyon plant investment to 6.77 percent and accelerating
the capital recovery of the plant and other utility generation-related
assets. If the proposal to freeze customer electric rates is adopted,
PG&E will depreciate and recover the Diablo Canyon plant balance at
January 1997 over five years rather than the current recovery period
through 2016. In addition, the proposal would also limit recovery of
most utility generation-related CTC to amounts collected through 2001.
While it would not adversely affect PG&E's cash flow, PG&E's proposal
to modify Diablo Canyon pricing and effect a customer electric rate
freeze and to accelerate recovery of utility generation-related
investments, including Diablo Canyon, and regulatory assets would
result in a significant reduction in annual earnings beginning in 1997.
If the revised return currently contemplated for Diablo Canyon had been
adopted for 1995 and PG&E recovered no more than its actual variable
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 variable
cost assumptions adopted by the CPUC in implementing PG&E's Diablo
Canyon pricing proposal. To the extent that the actual capacity factor
or variable expenses are different than those adopted by the CPUC in
setting the ICIP price, the Company's earnings will be impacted.
As of March 31, 1996, the net investment in Diablo Canyon and the
remaining PG&E-owned generation assets, including an allocation of
common plant, was approximately $4.8 billion and $3.0 billion,
respectively, and regulatory assets attributable to electric generation
(excluding balancing accounts expected to be recovered in the near
term) were approximately $1.4 billion. Because of the expected
transition cost recovery as provided in the decision, PG&E does not
anticipate a material impairment loss on its investment in generation
assets due to electric industry restructuring. However, should final
implementing regulations differ significantly from the CPUC decision or
should full recovery of generation assets and obligations not be
achieved due to changing costs or limitations imposed by the market, a
material loss could occur.
The Company cannot predict the ultimate outcome of the ongoing changes
that are taking place in the electric utility industry or predict
whether such outcome will have a material impact on its financial
position or results of operations. 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:
- --------------------------
In an effort to promote competition and increase options for all
customers, as well as to position itself for success in the competitive
marketplace, PG&E is actively pursuing changes in the California gas
industry. In October 1995, PG&E presented a proposal, called the "Gas
Accord," to numerous parties active in the California gas marketplace,
including consumer groups, industrial customers, shippers and
marketers. PG&E has invited these parties to join it in a
collaborative effort to develop a restructuring of the California gas
marketplace.
The Gas Accord proposes three broad initiatives:
(1) Increased Customer Choice - Under the Gas Accord, PG&E proposes to
give all customers greater ability to choose their gas suppliers in the
future. PG&E has formed an advisory group to help it design a program
that will facilitate opening of the residential and smaller commercial
(core) market for full competition.
(2) Separation of Transmission and Distribution Service and Rates -
PG&E proposes to charge separately for, or unbundle, its gas
transmission and distribution services. This would give industrial and
large commercial (noncore) customers and gas suppliers more flexibility
with respect to the purchase of gas transportation services.
(3) Resolution of Existing Regulatory Issues - PG&E also proposes to
settle several outstanding gas regulatory issues that are currently
pending at the CPUC in separate proceedings. These issues include
recovery of costs related to PG&E's capacity commitments with
Transwestern Pipeline Company (Transwestern), PG&E's capacity
commitments with El Paso Natural Gas Company and PGT related to its
noncore customers and the PG&E portion of the PGT/PG&E Pipeline
Expansion Project. (See Note 3 of Notes to Consolidated Financial
Statements.)
Negotiations on the Gas Accord began in October 1995. The Gas Accord,
if adopted, will result in a change in the way PG&E charges for its
transportation services. Any agreement reached by PG&E and other
parties must be approved by the CPUC before it may be implemented.
PG&E has also proposed a significant change to the current gas
ratemaking mechanisms. In December 1994, PG&E filed an application for
approval of a core procurement incentive mechanism (CPIM). If approved
by the CPUC, the CPIM would replace traditional reasonableness review
of PG&E's core gas costs with a market benchmark against which PG&E's
actual gas costs would be compared. PG&E would be able to fully
recover its gas costs, receive benefits or be penalized depending on
whether its actual core procurement costs are within, below or above
the "tolerance band" constructed around the benchmark. 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 benchmark.
In April 1996, PG&E filed revised CPIM testimony. In the revised CPIM,
PG&E has agreed to forgo its right to seek recovery of the core
reservation Transwestern costs for the period from 1992 through the end
of 1997, provided the revised CPIM is approved by the CPUC in a manner
satisfactory to PG&E. Hearings on the revised CPIM have been scheduled
for June 1996.
Based on the current status of the Gas Accord and CPIM negotiations,
the Company believes the ultimate outcome of such negotiations,
including resolution of gas regulatory issues, will not have a material
impact on its financial position or results of operations.
Holding Company Structure:
- -------------------------
The PG&E Board of Directors (Board) has authorized, and shareholders
have 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.
It is contemplated that these structural changes will be effected as
soon as practicable following receipt of all required regulatory
approvals, including approval by the CPUC, the FERC and the NRC. An
application for approval by the CPUC was filed by PG&E in October 1995
and PG&E subsequently filed for approvals from the FERC and the NRC.
Utility Revenue Matters:
- -----------------------
In addition to the CPUC decision on electric industry restructuring
(discussed above and in Note 2 of Notes to Consolidated Financial
Statements) and various gas proceedings (see 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. In December 1995, the CPUC issued its decision in
PG&E's 1996 GRC. Based on the GRC decision and the consolidation of the
electric rate cases that became effective January 1, 1996, including
the energy cost, cost of capital and various other proceedings, PG&E's
electric revenue decreased by $443 million from rates in effect in
1995. The GRC decision and various gas proceedings also resulted in an
overall gas revenue decrease of $211 million.
The 1996 GRC decision for base rates effective January 1, 1996,
authorized electric and gas base revenue decreases of approximately
$300 million and $270 million, respectively, compared to rates in
effect in 1995. The $570 million revenue decrease is attributable to
declining capital expenditures, lower cost of capital and reductions in
expense levels, principally relating to workforce reductions. PG&E has
filed an application for rehearing on a number of issues in the GRC
decision, including pension contributions, funding for nonresidential
customer service and elimination of the air quality adjustment
mechanism.
The GRC proceeding was held open to consider, among other things,
PG&E's response to outages caused by recent storms and a study to
determine the cost effectiveness of the Helms Pumped Storage Facility
(Helms). The study will consider changes in rate recovery for the
plant which will include, among other things, the option of retirement
with recovery of the investment without a return over a four-year
period. The net investment in Helms at March 31, 1996, was $719
million comprised of the pumped storage facility (including regulatory
assets of $50 million), common plant and dedicated transmission plant.
In December 1995, PG&E's service territory experienced severe storms
and winds which caused approximately 1.7 million electric service
interruptions. The assigned commissioner in the 1996 GRC subsequently
issued a ruling which ordered hearings on various issues arising from
PG&E's response to those wind storms. The hearings will also address
potential remedies, including reparations to customers for reduced
reliability, penalties, disallowances and damages to customers for
property loss. Hearings are expected to be held in June 1996.
Hearings on PG&E's compliance with call center improvements ordered by
the CPUC following severe storms in January and March 1995 have been
completed. A proposed CPUC decision on this phase of the storm
proceeding is expected shortly.
During March 1996, PG&E filed an application with the CPUC seeking
approval to modify Diablo Canyon pricing and adopt a customer electric
rate freeze, effective January 1, 1997, which would result in customer
electric rates in the years 1997 through 2001 being the same as those
in effect on January 1, 1996. See "Electric Industry Restructuring"
above. The filing seeks to accelerate PG&E's recovery of utility
generation-related transition costs caused by electric industry
restructuring. This accelerated recovery would increase 1997 Diablo
Canyon revenue requirement by $372 million. To achieve the customer
electric rate freeze, PG&E proposes to consolidate the revenue
requirement changes resulting from the proposed modification of Diablo
Canyon pricing and various other applications PG&E has filed, or will
be filing, at the CPUC in 1996. The more significant of these pending
applications are discussed below.
During April 1996, PG&E filed with the CPUC a rate case application to
increase 1997 electric base revenue by approximately $156 million, with
recovery of approximately $33 million effective January 1, 1997.
Recovery of the remaining $123 million would be deferred until January
1, 1998, unless otherwise offset by further decreases in other
forecasted electric costs for 1997. The filing requests recovery of
expenses for electric distribution operations and maintenance and call
center operations. The amounts requested are greater than the levels
authorized by the CPUC for these activities in the 1996 GRC. The
filing also requests an inflation adjustment from 1996 to 1997.
During April 1996, PG&E filed its 1997 Electric Cost Adjustment Clause
(ECAC) application with the CPUC to request a revenue requirement
decrease of approximately $405 million, composed of an ECAC decrease of
approximately $346 million, an Annual Energy Rate decrease of
approximately $10 million, an Energy Revenue Adjustment Mechanism
decrease of approximately $48 million and a California Alternative
Rates for Energy decrease of approximately $1 million.
During May 1996, PG&E filed an errata with the CPUC to correct errors
in the computation of its 1997 ECAC application. The errata filing
requested an additional decrease in revenue requirement of $97 million,
from $405 million, as originally requested, to $502 million. The
errata also requested a $97 million decrease in the deferral of the
proposed 1997 base revenue increase, as discussed above, from $123
million, as originally requested, to $26 million.
In May 1996, PG&E filed an application with the CPUC requesting the
following cost of capital for 1997:
Capital Cost/ Weighted
Ratio Return Cost/Return
------- ------ -----------
Common equity 48.00% 11.85% 5.69%
Preferred stock and
preferred securities 5.80% 7.04% .41%
Long-term debt 46.20% 7.50% 3.46%
-----
Total requested return
on average utility
rate base 9.56%
=====
If adopted, PG&E's request would result in an 1997 revenue requirement
increase of $13 million for electric rates and $4 million for gas rates
effective January 1, 1997. PG&E requested an increase in its return on
common equity from 11.60 percent, as adopted in the 1996 GRC, to 11.85
percent. The increase reflects higher interest rates and increased
regulatory and business risks.
During May 1996, PG&E filed its 1996 Annual Earnings Assessment
Proceeding application with the CPUC requesting shareholder incentives
for its Demand-Side Management programs. The filing requests a $13
million increase in the 1997 electric revenue requirement and a $1
million increase in the 1997 gas revenue requirement.
During May 1996, PG&E intends to file an application with the CPUC
seeking funding for costs associated with the establishment of the ISO
and Exchange. Such costs are currently estimated to range between $200
million and $300 million, with PG&E's share of the cost expected to
range from approximately $100 million to $150 million. The remainder
of the costs will be shared by the other two major California IOUs.
See "Electric Industry Restructuring," above. PG&E's annual recovery
in rates of these costs is limited by the CPUC to one percent of annual
billed electric revenue.
To implement the proposed customer electric rate freeze in 1997, PG&E
has requested or intends to request deferral of recovery in rates of a
portion of the electric revenue requirement increases proposed in the
above applications.
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-month period ended March 31,
1996 and 1995, are reflected in the following table and discussed
below.
<TABLE>
<CAPTION>
Diablo Diversified
(in millions, except per share amounts) Utility Canyon Operations Total
<S> <C> <C> <C> <C>
1996
Operating revenues $ 1,778 $ 440 $ 31 $ 2,249
Operating expenses 1,463 180 33 1,676
------- ------ ------ -------
Operating income (loss) before income taxes $ 315 $ 260 $ (2) $ 573
======= ====== ====== =======
Net income $ 128 $ 129 $ 4 $ 261
======= ====== ====== =======
Earnings per common share $ .29 $ .31 $ .01 $ .61
======= ====== ====== =======
Total assets at March 31 $19,916 $5,663 $1,055 $26,634
======= ====== ====== =======
1995
Operating revenues $ 1,777 $ 464 $ 67 $ 2,308
Operating expenses 1,335 183 81 1,599
------- ------ ------ -------
Operating income (loss) before income taxes $ 442 $ 281 $ (14) $ 709
======= ====== ====== =======
Net income (loss) $ 191 $ 140 $ (2) $ 329
======= ====== ====== =======
Earnings (loss) per common share $ .42 $ .32 $ (.01) $ .73
======= ====== ====== =======
Total assets at March 31 $19,928 $5,989 $1,423 $27,340
======= ====== ====== =======
</TABLE>
Earnings Per Common Share:
- -------------------------
Utility earnings per common share for the three-month period ended
March 31, 1996, decreased as compared with the same period 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.
Common Stock Dividend:
- ---------------------
In January 1996, the Board declared a quarterly dividend of $.49 per
common share which corresponds to an annualized dividend of $1.96 per
common share. 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 addition to the other factors affecting PG&E's
dividend policy, PG&E plans to evaluate the level of its common stock
dividend as key issues related to electric industry restructuring are
more clearly resolved.
Operating Revenues:
- ------------------
Billed revenues decreased for the three-month period ended March 31,
1996, compared to the same period in 1995 due to decreases in actual
energy usage as a result of a mild 1995/1996 winter season and in
authorized revenues, as discussed above. This decrease was offset by
an increase in balancing account revenues primarily due to lower than
forecasted energy demand and higher costs of fuel and transportation.
Therefore, there were no significant changes in total electric and gas
utility revenues for the three-month period ended March 31, 1996,
compared to the same period in 1995.
Revenues from diversified operations decreased $36 million for the
three-month period ended March 31, 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-month period ended March 31, 1996,
increased $76 million compared to the same period in 1995 primarily due
to expenses incurred to terminate certain qualifying facility (QF)
contracts, increases in the price of gas and increases in maintenance
and other operating expenses for distribution and customer-related
services. Partially offsetting these increases were decreases in
general and administrative expenses, depreciation and litigation
reserves. Operating expenses for the three-month period ended March
31, 1996, were also greater than amounts authorized by the CPUC for
setting rates in the 1996 GRC. The greater expense level is primarily
attributable to several projects related to distribution system
reliability, improved customer service and public information systems.
During April 1996, PG&E filed with the CPUC a rate case application to
increase 1997 electric base revenues. The filing requests recovery of
expenses for electric distribution operations and maintenance and call
center operations. (See "Utility Revenue Matters" above.)
Liquidity and Capital Resources
- -------------------------------
Sources 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 three-month period ended March 31,
1996, PG&E issued $58 million of common stock, primarily through its
Dividend Reinvestment Program and Savings Fund Plan. PG&E purchased
approximately $39 million of its common stock on the open market during
the three-month period ended March 31, 1996.
Acquisition:
- -----------
In April 1996, the Company was chosen by the State of Queensland in
Australia as the selected bidder for State Gas Pipeline, a 376-mile
natural gas transportation system in northeastern Australia. The
Company has granted another company a 60-day option which expires in
June 1996 to purchase up to 50 percent of State Gas Pipeline. The
purchase price is approximately $130 million. State Gas Pipeline
provides gas transportation service to the industrial sector in the
Australian state of Queensland, primarily supplying gas as a process
fuel in industrial applications.
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 activities.
The Company has an accrued liability at March 31, 1996, of $126 million
for hazardous waste remediation costs at those sites where such costs
are probable and quantifiable. The costs may be as much as $292
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. (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 have been
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. These cases involve claims for
personal injury, and property and punitive damages allegedly suffered
as a result of exposure to chromium near PG&E's Hinkley Compressor
Station and a claim that PG&E underpaid franchise fees.
Other Matters
- -------------
New Accounting Standard:
- -----------------------
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of," effective January 1, 1996,
prescribes general standards for the recognition and measurement of
impairment losses. In addition, it requires that regulatory assets
continue to be probable of recovery in rates, rather than only at the
time the regulatory asset is recorded. Regulatory assets currently
recorded would be written off if recovery is no longer probable.
Based on the expected CTC recovery set forth in the CPUC decision on
electric industry restructuring discussed in Note 2 of Notes to
Consolidated Financial Statements, the Company currently does not
anticipate a material impairment of its assets and, specifically, its
generation-related regulatory assets and investments in electric
generation assets. However, the CPUC decision is subject to
legislative review. Should final regulations differ significantly from
the CPUC decision or should full recovery of generation assets and
obligations not be achieved due to changing costs or limitations
imposed by the market, a material loss could occur.
Accounting for Decommissioning Expense:
- --------------------------------------
The staff of the Securities and Exchange Commission has questioned
certain current accounting practices of the electric utility industry
regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. In response to these questions, the
Financial Accounting Standards Board (FASB) has issued an Exposure
Draft of a proposed new accounting standard, "Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets." The
Company would be required to adopt the new standard beginning January
1, 1997, but may elect to adopt it earlier.
If issued by the FASB as proposed, the new standard would require,
among other things, that a liability be recognized for decommissioning
costs rather than accruing these costs over time as accumulated
depreciation, with recognition of an increase in the cost of the
related nuclear power plant. It would also require, upon initial
application, a cumulative-effect adjustment for the effect on retained
earnings had the provisions of this proposed Statement been applied
when those obligations were incurred. The Company does not believe
that such changes, if required, would have an adverse effect on its
results of operations due to its current and future ability to recover
decommissioning costs through rates.
PART II. OTHER INFORMATION
---------------------------
1. Legal Proceedings
-----------------
A. Diablo Canyon Environmental Litigation
As previously reported, in October 1995, the League for Coastal
Protection (Coastal League) filed a lawsuit in San Francisco County
Superior Court against Pacific Gas and Electric Company (PG&E) and its
consultant, Tenera, Inc., (Tenera) alleging violations of the
California Business and Professions Code in connection with a 1988
study of the cooling water intake system (1988 Study) at the Diablo
Canyon Nuclear Power Plant (Diablo Canyon). (The 1988 Study is also
the subject of an investigation by the California Attorney General, as
described in Item B below.) The Coastal League alleges in this
lawsuit that PG&E and its consultant violated the law by making
misrepresentations in connection with the 1988 Study. The Coastal
League seeks an unspecified amount of damages related to restitution
or disgorgement of improper or excessive profits, punitive damages,
injunctive relief and attorneys' fees.
On April 16, 1996, the Coastal League filed another lawsuit in the
United States District Court for the Northern District of California
against PG&E and Tenera, alleging violations of the federal Clean
Water Act in connection with the 1988 Study. The Coastal League
alleges that PG&E and Tenera withheld data from the 1988 Study and
submitted misleading information to the state and federal agencies.
The Coastal League seeks a judgment that PG&E has violated its
discharge permit for Diablo Canyon, revocation of the permit, an order
requiring restoration of the marine environment, an unspecified amount
of civil penalties and recovery of its litigation and attorneys' fees.
Also on April 16, 1996, PG&E received a copy of a complaint filed in a
third case involving the 1988 study. In this case, John W. Carter
(Carter) alleges on behalf of himself and the United States and the
State of California that PG&E, Tenera, and certain of their employees
violated the federal and state false claims acts by filing an
incomplete report in 1988 (i.e., the 1988 Study) and failing to
correct it. The United States and the State of California have
declined to prosecute this action, and it will be maintained by
Carter, who is represented by the same attorneys representing the
Coastal League. The plaintiffs seek civil penalties, treble damages,
a separate payment to Carter under the false claims acts and
attorneys' fees.
The Company believes that the ultimate outcome of these matters will
not have a material adverse impact on its financial position or
results of operations.
B. California Attorney General Litigation
As previously reported, in February 1995, the California Attorney
General (AG) initiated an investigation to determine whether PG&E and
its consultant, Tenera, Inc., violated the Federal Clean Water Act and
the California Water Code in connection with the 1988 Study, which is
also the subject of litigation described in Item A above. The United
States Department of Justice (DOJ) has recently joined the AG's
investigation. PG&E has been in discussions with the AG and the DOJ
concerning the disposition of this matter. In those discussions, the
AG and the DOJ have indicated their belief that PG&E violated the
Federal Clean Water Act, the California Water Code and other
provisions of California law in connection with the 1988 Study. The
AG and DOJ have proposed a resolution of this matter which involves
the payment by PG&E of civil penalties and mitigation project costs.
While PG&E cannot predict the outcome of these discussions, the
disposition of the matter is likely to involve the initiation of legal
proceedings against PG&E by the AG or the payment of a monetary fine
by PG&E.
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.
C. Norcen Litigation
As previously reported, in March 1994, Norcen Energy Resources Limited
and Norcen Marketing Incorporated filed a complaint in the U.S.
District Court, Northern District of California, against PG&E and
Pacific Gas Transmission Company (PGT), alleging various state law
contract claims and a series of federal and state antitrust claims
related to the construction of the PGT/PG&E Pipeline Expansion and
PG&E's alleged refusals to allow access to the pre-expansion PGT and
California transmission systems. Plaintiffs' antitrust claims were
dismissed by the District Court in July 1995. The remaining state law
contract claims include claims based on fraudulent inducement and
breach of contract. The Company believes plaintiffs in this action
might seek contract damages of approximately $50 million. The
plaintiffs are also seeking punitive damages in connection with such
claims.
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.
Item 4. Submission of Matters to a Vote of Security-Holders
----------------------------------------------------
On April 17, 1996, PG&E held its regular annual meeting of
shareholders. At that meeting, the following matters were voted as
indicated:
1. Election of the following directors to serve until the next annual
meeting of shareholders or until their successors shall be elected
and qualified:
For Withheld
---------- ----------
Richard A. Clarke 340,588,268 9,842,499
Harry M. Conger 343,885,360 6,545,407
C. Lee Cox 341,066,532 9,364,235
William S. Davila 343,880,297 6,550,470
Robert D. Glynn, Jr. 341,876,054 8,554,713
David M. Lawrence, MD 341,105,754 9,325,013
Simon Levine 158,884 0
Richard B. Madden 343,726,090 6,704,677
Mary S. Metz 343,581,080 6,849,687
Rebecca Q. Morgan 341,079,589 9,351,178
Samuel T. Reeves 343,651,071 6,779,696
Carl E. Reichardt 343,755,340 6,675,427
John C. Sawhill 343,877,184 6,553,583
Alan Seelenfreund 342,990,320 7,440,447
Stanley T. Skinner 341,218,835 9,211,932
Barry Lawson Williams 343,740,843 6,689,924
2. Approval of a proposal to form a holding company structure for
PG&E and approve a related agreement of merger to implement this
structure:
Common and Preferred Stock Common Stock Alone
-------------------------- ------------------
For: 292,100,933 278,365,856
Against: 11,071,318 10,040,910
Abstain: 5,818,552 5,427,877
Broker non-votes*: 41,439,964 38,193,617
3. Approval of a proposal to amend and restate PG&E's Long-Term
Incentive Program:
For: 267,999,694
Against: 32,062,670
Abstain: 8,863,607
Broker non-votes*: 41,504,796
4. Ratification of the selection of Arthur Andersen LLP as
independent public accountants for the year 1996:
For: 341,761,225
Against: 4,092,404
Abstain: 4,577,138
Broker non-votes*: 0
5. Approval of a shareholder proposal to limit each director's total
annual compensation to 2,000 shares of PG&E's common stock:
For: 41,930,355
Against: 251,721,345
Abstain: 15,335,779
Broker non-votes*: 41,443,288
- ----------------------------------
* A non-vote occurs when a nominee holding shares for a beneficiary
owner votes on one proposal, but does not vote on another proposal
because the nominee does not have discretionary voting power and has
not received instructions from the beneficial owner.
Item 5. Other Information
-----------------
A. Pending Electric Reasonableness Issue
In August 1993, the Division of Ratepayer Advocates (DRA) of the
California Public Utilities Commission (CPUC) filed a report in PG&E's
Electric Cost Adjustment Clause (ECAC) proceeding for the 1991 record
period, which questioned PG&E's execution of amendments to three power
purchase agreements (PPAs) with Texaco, Inc. (Texaco) for qualifying
facilities (QFs). The PPAs were Standard Offer No. 4 contracts
providing for relatively high capacity payments, and included the
standard provision that the agreements would terminate if construction
was not completed and energy deliveries commenced within five years of
the execution of the PPAs in 1985. In its report, the DRA asserted
that PG&E improperly agreed to extend the construction time under
these agreements and recommended that the CPUC find these extensions
unreasonable because Texaco could not fulfill its contractual
obligation to commence operations by a date certain. Although no
payments are at issue in the 1991 record period, the DRA argued that a
portion of the capacity payments under the contracts should be
disallowed in subsequent year proceedings over the 15-year term of the
contracts. In its August 1993 report, the DRA indicated that this
disallowance over the 15-year terms of the contracts would approximate
$80 million. In its report on the ECAC expenses for the 1992, 1993 and
1994 record periods, the DRA recommended disallowances of
approximately $3.5 million, $3.0 million and $6.1 million,
respectively, for two of these agreements.
On May 8, 1996, the CPUC issued its decision addressing this issue,
finding that PG&E's deferral of the deadline by which these QFs were
required to come on-line was reasonable. The CPUC agreed with PG&E
that the appropriate starting point for review was the spring of 1988,
when the contract deferrals were negotiated and agreement in principle
was reached, as opposed to December 1988 when the extensions were
actually executed. At the earlier date when the extensions were
negotiated, the facts and then-existing viability standards indicated
that the projects were viable, and the QFs could have come on-line on
or before the original contractual deadline. Accordingly, under this
analysis PG&E acted reasonably in granting the extensions.
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 three months ended
March 31, 1996 was 3.35. PG&E's earnings to combined fixed charges
and preferred stock dividends ratio for the three months ended
March 31, 1996 was 3.13. 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
Exhibit 99 Deferrable Interest Subordinated Debenture Second
Supplemental Indenture dated as of March 25, 1996
(b) Reports on Form 8-K during the first quarter of 1996 and
through the date hereof:
1. January 17, 1996
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. Performance Incentive Plan - 1996 Target
C. 1995 Consolidated Earnings (unaudited)
D. Common Stock Dividend
2. January 18, 1996 (Form 8K/A)
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. Performance Incentive Plan - 1996 Target
C. 1995 Consolidated Earnings (unaudited)
D. Common Stock Dividend
3. February 21, 1996
Item 7. Financial Statements, Pro Forma Financial
Information and Exhibits
A. 1995 Financial Statements
B. Ratios of Earnings to Fixed Charges and Ratios of
Earnings to Combined Fixed Charges and Preferred Stock
Dividends
4. April 18, 1996
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. Interim CTC Procedure
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
May 9, 1996 GORDON R. SMITH
By______________________________
GORDON R. SMITH
Senior Vice President and
Chief Financial Officer
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
99 Deferrable Interest Subordinated Debenture
Second Supplemental Indenture dated as of
March 25, 1996
<TABLE>
EXHIBIT 11
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
<CAPTION>
- --------------------------------------------------------------------------------------------
Three months ended March 31,
---------------------------
(in thousands, except per share amounts) 1996 1995
- --------------------------------------------------------------------------------------------
<S> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income $260,704 $328,687
Less: preferred dividend requirement and
redemption premium 8,278 14,494
-------- --------
Net income for calculating EPS for
Statement of Consolidated Income $252,426 $314,193
======== ========
Average common shares outstanding 414,351 430,086
======== ========
EPS as shown in the Statement of
Consolidated Income $ .61 $ .73
======== ========
PRIMARY EPS (1)
Net income $260,704 $328,687
Less: preferred dividend requirement and
redemption premium 8,278 14,494
-------- --------
Net income for calculating primary EPS $252,426 $314,193
======== ========
Average common shares outstanding 414,351 430,086
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) 83 46
-------- --------
Average common shares outstanding as
adjusted 414,434 430,132
======== ========
Primary EPS $ .61 $ .73
======== ========
FULLY DILUTED EPS (1)
Net income $260,704 $328,687
Less: preferred dividend requirement and
redemption premium 8,278 14,494
-------- --------
Net income for calculating fully diluted EPS $252,426 $314,193
======== ========
Average common shares outstanding 414,351 430,086
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) 83 46
-------- --------
Average common shares outstanding as
adjusted 414,434 430,132
======== ========
Fully diluted EPS $ .61 $ .73
======== ========
- --------------------------------------------------------------------------------------------
<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>
- ----------------------------------------------------------------------------------------------------
Three Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) 3/31/96 1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 260,704 $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 (6,529) 3,820 (2,764) 6,895 (3,349) 26,671
Income tax expense 171,544 895,289 836,767 901,890 895,126 851,534
Net fixed charges 181,194 715,975 730,965 821,166 802,198 776,682
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $ 606,913 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 147,242 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185
Interest on short-
term borrowings 26,975 83,024 77,295 87,819 61,182 77,760
Interest on capital
leases 895 2,735 1,758 1,737 1,737 1,737
Capitalized interest 109 957 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 6,191 3,306 - - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $ 181,412 $ 717,397 $ 733,625 $ 867,221 $ 808,709 $ 782,789
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 3.35 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>
- ---------------------------------------------------------------------------------------------------
Three Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) 3/31/96 1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 260,704 $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 (6,529) 3,820 (2,764) 6,895 (3,349) 26,671
Income tax expense 171,544 895,289 836,767 901,890 895,126 851,534
Net fixed charges 181,194 715,975 730,965 821,166 802,198 776,682
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $ 606,913 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 147,242 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185
Interest on short-
term borrowings 26,975 83,024 77,295 87,819 61,182 77,760
Interest on capital
leases 895 2,735 1,758 1,737 1,737 1,737
Capitalized interest 109 957 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 6,191 3,306 - - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 181,412 717,397 733,625 867,221 808,709 782,789
---------- ---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 2,514 11,343 4,672 4,814 5,136 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 9,777 99,984 96,039 108,937 130,147 154,404
---------- ---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 12,291 111,327 100,711 113,751 135,283 159,540
---------- ---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 193,703 $ 828,724 $ 834,336 $ 980,972 $ 943,992 $ 942,329
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 3.13 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> 3-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> MAR-31-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 18,807,712
<OTHER-PROPERTY-AND-INVEST> 1,827,902
<TOTAL-CURRENT-ASSETS> 3,380,889
<TOTAL-DEFERRED-CHARGES> 2,617,835
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 26,634,338
<COMMON> 2,073,473
<CAPITAL-SURPLUS-PAID-IN> 3,749,153
<RETAINED-EARNINGS> 2,836,255
<TOTAL-COMMON-STOCKHOLDERS-EQ> 8,658,881
437,500
402,056
<LONG-TERM-DEBT-NET> 7,985,999
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 763,304
<LONG-TERM-DEBT-CURRENT-PORT> 230,342
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 8,156,256
<TOT-CAPITALIZATION-AND-LIAB> 26,634,338
<GROSS-OPERATING-REVENUE> 2,248,768
<INCOME-TAX-EXPENSE> 171,544
<OTHER-OPERATING-EXPENSES> 1,675,374
<TOTAL-OPERATING-EXPENSES> 1,675,374
<OPERATING-INCOME-LOSS> 573,394
<OTHER-INCOME-NET> 32,782
<INCOME-BEFORE-INTEREST-EXPEN> 606,176
<TOTAL-INTEREST-EXPENSE> 173,928
<NET-INCOME> 260,704
8,278
<EARNINGS-AVAILABLE-FOR-COMM> 252,426
<COMMON-STOCK-DIVIDENDS> 200,998
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 931,163
<EPS-PRIMARY> .61
<EPS-DILUTED> .61
</TABLE>
Exhibit 99
PACIFIC GAS AND ELECTRIC COMPANY
TO
THE FIRST NATIONAL BANK OF CHICAGO
Trustee
-----------------
SECOND SUPPLEMENTAL INDENTURE
Dated as of March 25, 1996
TO
Indenture
Dated as of November 28, 1995
-----------------
SECOND SUPPLEMENTAL INDENTURE, dated as of March 25,
1996, (the "Second Supplemental Indenture"), between Pacific Gas
and Electric Company, a California corporation (the "Company"),
and The First National Bank of Chicago, a national banking
association organized under the laws of the United States, as
trustee (the "Trustee"), under the Indenture dated as of November
28, 1995, between the Company and the Trustee (the "Indenture"),
as supplemented by the First Supplemental Indenture between the
Company and the Trustee dated as of November 28, 1995 (the "First
Supplemental Indenture").
WHEREAS, the Company and the Trustee executed the First
Supplemental Indenture providing for the issuance by the Company
of its 7.90% Deferrable Interest Subordinated Debentures, Series
A (the "Debentures");
WHEREAS, Section 901(10) of the Indenture provides for
the issuance of a Supplemental Indenture by the Company and the
Trustee without the consent of the holders of the Debentures to,
among other things, cure any ambiguity or correct or supplement
any provision in the Indenture; and
WHEREAS, the Company had intended that it have the
right to extend the interest payment period on the Debentures
only so long as an Event of Default under the Indenture has not
occurred and is continuing at the time of such extension
notwithstanding the absence of such restriction in the First
Supplemental Indenture.
NOW THEREFORE, THIS SECOND SUPPLEMENTAL INDENTURE WITNESSETH:
SECTION 101.
The following clause shall be added at the beginning of
the first sentence of the second paragraph under "Section 101 -
Title; Stated Maturity; Interest" in the First Supplemental
Indenture: "So long as an Event of Default under the Indenture
has not occurred and is continuing," and, accordingly, such
paragraph shall read in its entirety as follows:
"So long as an Event of Default under the Indenture has
not occurred and is continuing, the Company shall have the right,
at any time during the term of the Series A Securities, from time
to time to extend the interest payment period for up to 20
consecutive quarters (the "Extension Period") during which period
interest will compound quarterly, and at the end of which
Extension Period the Company shall pay all interest then accrued
and unpaid thereon (together with Additional Interest), provided,
however, that during any such Extension Period, the Company shall
not, and shall not permit any Subsidiary of the Company to,
declare or pay any dividend or distribution on, or redeem,
purchase, acquire, or make a liquidation or guarantee payment
(other than payments under a Guarantee) with respect to, any
shares of the Company's capital stock or any other security of
the Company (including other Securities) ranking pari passu with
or junior in interest to the Series A Securities, except in each
case with securities ranking junior in interest to the Series A
Securities and except for payments made on any series of
Securities upon the Stated Maturity of such Securities. Prior to
the termination of any such Extension Period, the Company may
further extend the interest payment period, provided that such
Extension Period together with all such previous and further
extensions thereof shall not exceed 20 consecutive quarters or
extend beyond the Maturity of the Series A Securities. Upon the
termination of any Extension Period and upon the payment of all
accrued and unpaid interest and any Additional Interest then due,
the Company may select a new Extension Period, subject to the
above requirements. No interest or Additional Interest shall be
due and payable during an Extension Period, except at the end
thereof. The Company shall give the Series A Trust and the
Trustee notice of its selection of such Extension Period subject
to the above requirements at least one Business Day prior to the
date the Series A Trust is required to give notice to the New
York Stock Exchange or other applicable self-regulatory
organization or to holders of the Series A Preferred Securities
of the record date or the date distributions on the Series A
Preferred Securities are payable, but in any event not less than
one Business Day prior to such record date. The Trustee shall
promptly notify the holders of the Series A Preferred Securities
of the Company's selection of such an Extension Period."
IN WITNESS WHEREOF, the parties hereto have caused this
Second Supplemental Indenture to be duly executed, and their
respective corporate seals to be hereunto affixed and attested,
on the date or dates indicated in the acknowledgements and as of
the day and year first above written.
PACIFIC GAS AND ELECTRIC COMPANY
GORDON R. SMITH
By: ______________________________
Gordon R. Smith
Senior Vice President
and Chief Financial Officer
Attest:
KATHLEEN RUEGER
______________________________
Kathleen Rueger
Assistant Corporate Secretary
[Continuation of signature page for Second Supplemental
Indenture]
THE FIRST NATIONAL BANK OF CHICAGO
as Trustee
JOHN R. PRENDIVILLE
By:___________________________
Name: John R. Prendiville
Title: Vice President
Attest:
R. D. MANELLA
____________________
Name: R. D. Manella
Secretary
