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 June 30, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File No. 1-2348
PACIFIC GAS AND ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
California 94-0742640
- ---------------------------- -------------------
(State or other jurisdiction of (I.R.S. 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 July 29, 1994
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Common Stock, $5 par value 432,042,842 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
Nuclear Decommissioning Costs................ 5
Note 2: Electric Industry Restructuring................ 6
Note 3: Reasonableness Proceedings..................... 7
Note 4: Contingencies
Helms Pumped Storage Plant................... 10
Nuclear Insurance............................ 10
Environmental Remediation.................... 10
Legal Matters................................ 11
Item 2. Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Results of Operations
Earnings Per Common Share............................. 14
Common Stock Dividend................................. 15
Operating Revenues.................................... 15
Operating Expenses.................................... 16
Diablo Canyon......................................... 16
Changing Competitive and Regulatory Environment....... 16
Rate Matters.......................................... 23
Reasonableness Proceedings............................ 27
Legal Matters......................................... 27
Liquidity and Capital Resources
Sources of Capital.................................... 30
Environmental Remediation............................. 30
Sales and Acquisition ................................ 31
PART II. OTHER INFORMATION
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Item 1. Legal Proceedings
QF Transmission Constrained Area Litigation........... 33
Time-of-Use Meter Litigation.......................... 33
Item 5. Ratios of Earnings to Fixed Charges and Ratios of
Earnings to Combined Fixed Charges and Preferred
Stock Dividends....................................... 33
Item 6. Exhibits and Reports on Form 8-K........................ 34
SIGNATURE.......................................................... 36
PART I. FINANCIAL INFORMATION
------------------------------
Item 1. Consolidated Financial Statements
---------------------------------
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(unaudited)
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Three months ended June 30, Six months ended June 30,
(in thousands, -------------------------- -------------------------
except per share amounts) 1994 1993 1994 1993
- --------------------------------------------------------------------------------------------
OPERATING REVENUES
Electric $1,904,231 $1,830,055 $3,720,208 $3,552,344
Gas 535,449 634,070 1,233,743 1,375,599
---------- ---------- ---------- ----------
Total operating revenues 2,439,680 2,464,125 4,953,951 4,927,943
---------- ---------- ---------- ----------
OPERATING EXPENSES
Cost of electric energy 648,627 474,786 1,195,588 910,249
Cost of gas 73,378 180,237 334,764 484,084
Distribution 55,917 53,991 112,980 109,223
Transmission 64,354 88,056 137,046 179,685
Customer accounts and services 96,440 93,965 186,554 182,451
Maintenance 115,498 118,788 229,154 236,954
Depreciation and decommissioning 345,310 321,542 693,743 639,996
Administrative and general 267,819 233,248 462,988 497,840
Workforce reduction costs - 141,200 - 141,200
Income taxes 210,883 191,487 460,593 389,300
Property and other taxes 75,424 74,658 156,239 157,705
Other 90,325 104,460 173,923 191,220
---------- ---------- ---------- ----------
Total operating expenses 2,043,975 2,076,418 4,143,572 4,119,907
---------- ---------- ---------- ----------
OPERATING INCOME 395,705 387,707 810,379 808,036
---------- ---------- ---------- ----------
OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 17,129 18,555 36,570 42,020
Allowance for equity funds used
during construction 5,058 11,758 9,737 21,461
Other--net 4,598 18,986 (3,766) 8,145
---------- ---------- ---------- ----------
Total other income and
(income deductions) 26,785 49,299 42,541 71,626
---------- ---------- ---------- ----------
INCOME BEFORE INTEREST EXPENSE 422,490 437,006 852,920 879,662
---------- ---------- ---------- ----------
INTEREST EXPENSE
Interest on long-term debt 167,468 175,447 323,192 350,733
Other interest charges 17,444 23,466 59,185 50,174
Allowance for borrowed funds used
during construction (3,787) (7,257) (7,774) (22,259)
---------- ---------- ---------- ----------
Net interest expense 181,125 191,656 374,603 378,648
---------- ---------- ---------- ----------
NET INCOME 241,365 245,350 478,317 501,014
Preferred dividend requirement 14,362 16,633 28,820 33,393
---------- ---------- ---------- ----------
EARNINGS AVAILABLE FOR
COMMON STOCK $ 227,003 $ 228,717 $ 449,497 $ 467,621
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING 429,762 430,639 429,150 429,539
EARNINGS PER COMMON SHARE $.53 $.53 $1.05 $1.09
DIVIDENDS DECLARED PER COMMON SHARE $.49 $.47 $ .98 $ .94
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
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June 30, December 31,
(in thousands) 1994 1993
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ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $ 16,925,479 $ 16,633,772
Diablo Canyon 6,569,590 6,518,413
Gas 7,311,386 7,146,741
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Total plant in service (at original cost) 30,806,455 30,298,926
Accumulated depreciation and decommissioning (11,849,371) (11,235,519)
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Net plant in service 18,957,084 19,063,407
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CONSTRUCTION WORK IN PROGRESS 529,828 620,187
OTHER NONCURRENT ASSETS
Oil and gas properties 505,982 573,523
Nuclear decommissioning funds 587,445 536,544
Other assets 663,084 497,689
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Total other noncurrent assets 1,756,511 1,607,756
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CURRENT ASSETS
Cash and cash equivalents 98,668 61,066
Accounts receivable
Customers 1,310,845 1,264,907
Other 130,541 123,255
Allowance for uncollectible accounts (26,780) (23,647)
Regulatory balancing accounts receivable 1,158,990 992,477
Inventories
Materials and supplies 234,351 239,856
Gas stored underground 145,293 170,345
Fuel oil 94,331 109,615
Nuclear fuel 145,230 134,411
Prepayments 39,779 56,062
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Total current assets 3,331,248 3,128,347
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DEFERRED CHARGES
Income tax-related deferred charges 1,085,260 1,246,890
Diablo Canyon costs 410,760 419,775
Unamortized loss net of gain on reacquired debt 391,798 395,659
Workers' compensation and disability claims recoverable 282,417 192,203
Other 476,756 488,302
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Total deferred charges 2,646,991 2,742,829
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TOTAL ASSETS $ 27,221,662 $ 27,162,526
============ ============
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<FN>
(continued on next page)
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
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June 30, December 31,
(in thousands) 1994 1993
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CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,147,814 $ 2,136,095
Additional paid-in capital 3,745,986 3,666,455
Reinvested earnings 2,632,273 2,643,487
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Total common stock equity 8,526,073 8,446,037
Preferred stock without mandatory redemption provision 732,995 807,995
Preferred stock with mandatory redemption provision 137,500 75,000
Long-term debt 9,018,531 9,292,100
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Total capitalization 18,415,099 18,621,132
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OTHER NONCURRENT LIABILITIES
Customer advances for construction 151,289 152,872
Workers' compensation and disability claims 249,000 157,000
Other 367,023 246,950
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Total other noncurrent liabilities 767,312 556,822
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CURRENT LIABILITIES
Short-term borrowings 635,012 764,163
Long-term debt 303,994 221,416
Accounts payable
Trade creditors 370,885 472,985
Other 436,577 389,065
Accrued taxes 449,529 303,575
Deferred income taxes 368,253 315,584
Interest payable 93,160 82,105
Dividends payable 227,059 203,923
Other 423,378 487,809
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Total current liabilities 3,307,847 3,240,625
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DEFERRED CREDITS
Deferred income taxes 3,809,524 3,978,950
Deferred investment tax credits 402,778 410,969
Other 519,102 354,028
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Total deferred credits 4,731,404 4,743,947
CONTINGENCIES (Notes 2, 3 and 4) - -
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TOTAL CAPITALIZATION AND LIABILITIES $27,221,662 $27,162,526
=========== ===========
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
(unaudited)
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Six months ended June 30,
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(in thousands) 1994 1993
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CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 478,317 $ 501,014
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and decommissioning 693,743 639,996
Amortization 33,530 36,854
Deferred income taxes and investment tax credits--net 26,893 (43,742)
Allowance for equity funds used during construction (9,737) (21,461)
Net effect of changes in operating assets
and liabilities
Accounts receivable (50,091) 33,769
Regulatory balancing accounts receivable (166,513) 103,766
Inventories 35,022 12,152
Accounts payable (54,588) 9,773
Accrued taxes 156,633 110,018
Other working capital (36,849) 153,097
Other deferred charges (14,770) (57,628)
Other noncurrent liabilities 50,534 (35,007)
Other deferred credits 167,850 27,048
Other--net 13,876 (10,074)
---------- ----------
Net cash provided by operating activities 1,323,850 1,459,575
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CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures (458,909) (954,928)
Allowance for borrowed funds used during construction (7,774) (22,259)
Nonregulated expenditures (163,968) (57,614)
Other--net 16,931 (4,688)
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Net cash used by investing activities (613,720) (1,039,489)
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CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 138,768 151,008
Common stock repurchased (60,320) (4,541)
Preferred stock issued 62,312 75,000
Preferred stock redeemed (82,995) (132,784)
Long-term debt issued 55,000 1,159,650
Long-term debt matured or reacquired (230,245) (938,815)
Short-term debt redeemed--net (129,151) (281,427)
Dividends paid (441,277) (422,820)
Other--net 15,380 (11,282)
---------- ----------
Net cash used by financing activities (672,528) (406,011)
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NET CHANGE IN CASH AND CASH EQUIVALENTS 37,602 14,075
CASH AND CASH EQUIVALENTS AT JANUARY 1 61,066 97,592
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CASH AND CASH EQUIVALENTS AT JUNE 30 $ 98,668 $ 111,667
========== ==========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 338,144 $ 338,124
Income taxes 232,519 312,005
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
NOTE 1: GENERAL
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Basis of Presentation:
- ---------------------
The accompanying unaudited consolidated financial statements of
Pacific Gas and Electric Company (PG&E) and its wholly owned and
majority-owned subsidiaries (collectively, the Company) have been
prepared in accordance with the interim period reporting requirements
of Form 10-Q. This information should be read in conjunction with
the Consolidated Financial Statements and Notes to Consolidated
Financial Statements incorporated by reference in the 1993 Annual
Report on Form 10-K.
In the opinion of management, the accompanying statements reflect all
adjustments 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 1994 presentation. Results of operations
for interim periods are not necessarily indicative of results to be
expected for a full year.
Nuclear Decommissioning Costs:
- -----------------------------
The estimated total obligation for nuclear decommissioning costs is
approximately $1.1 billion in 1994 dollars (or $4.5 billion in
escalated dollars); this obligation is being recognized ratably over
the facilities' lives. This estimate considers the total cost
(including labor, materials and other costs) of decommissioning and
dismantling plant systems and structures and includes a contingency
factor for possible changes in regulatory requirements and waste
disposal cost increases.
The decommissioning method selected for Diablo Canyon anticipates the
equipment, structures, and portions of the facility and site
containing radioactive contaminants will be removed or decontaminated
to a level that permits the property to be released for unrestricted
use shortly after cessation of operations. Humboldt Bay Power Plant
is being decommissioned under a method that consists of placing and
maintaining the facility in protective storage until some future time
when dismantling can be initiated.
As of June 30, 1994, the Company had accumulated in external trust
funds $587 million (at fair value) to be used for the decommissioning
of its nuclear facilities. The average annualized escalation rate
and the assumed return on qualified trust assets used to calculate
the decommissioning obligation are approximately 5.5 percent and 5.25
percent (6.25 percent on nonqualified trust assets), respectively.
NOTE 2: ELECTRIC INDUSTRY RESTRUCTURING
- ----------------------------------------
California Public Utilities Commission (CPUC) Electric Industry
Restructuring Proposal: In April 1994, the CPUC issued an order
instituting a rulemaking and an investigation (OIR/OII) on electric
industry restructuring. The proposal, which is subject to comment and
modification, involves two major changes in electric industry
regulation. The first would move electric utilities from traditional
cost-of-service regulation to performance-based ratemaking. The second
would unbundle electric services and provide electric utility retail
customers the option to choose from a range of electric generation
providers, including utilities (direct access). Direct access would be
phased in over a six-year period from 1996 to 2002. The utility would
still be obligated to provide transmission and distribution services to
all customers. To ensure an orderly transition that maintains the
financial integrity of the utilities, the CPUC proposed that stranded
costs of utility generating assets be recovered through a "competition
transition charge." However, the OIR/OII did not specify which costs
might be recovered through such a transition charge nor how such a
charge would be allocated to and collected from customers.
In June 1994, the Company filed its initial comments on the CPUC's
proposal. The Company's response proposed an implementation schedule
for direct access beginning in 1996, with direct access service
available to all customers by 2008. If the Company's proposed
implementation schedule is adopted, it will request recovery of certain
incurred and committed costs through the transition charge, but will
not request recovery of transition costs associated with its electric
generation facilities. For direct access customers, the Company
proposed that it be given the pricing flexibility to compete and sell
unbundled electric power while assuming the market risk of competitive
pricing. The Company indicated that its proposed schedule, coupled
with pricing flexibility, will permit the Company sufficient time to
reduce its generation costs and recover its investments in facilities.
The CPUC has indicated that it anticipates adopting a final policy
statement no earlier than October 1994. However, this policy statement
will be subject to state legislative review before it can be
implemented by the CPUC. (See Changing Competitive and Regulatory
Environment in Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition for further discussion.)
Financial Impact of the Electric Industry Restructuring Proposal:
Based on the regulatory framework in which it operates, the Company
currently accounts for the economic effects of regulation in accordance
with the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." As a result of applying the provisions of SFAS No. 71,
the Company has accumulated approximately $3.5 billion of regulatory
assets, including balancing accounts, as of June 30, 1994.
In the event that recovery of specific costs through rates becomes
unlikely or uncertain for all or a portion of the Company's utility
operations, whether resulting from the expanding effects of competition
or specific regulatory actions which move the Company away from cost-
of-service ratemaking, SFAS No. 71 would no longer apply.
Discontinuation of SFAS No. 71 would cause the write-off of applicable
portions of regulatory assets, which could have a significant adverse
impact on the Company's financial position or results of operations.
If the OIR/OII is adopted it would impact the future application of
SFAS No. 71 for the electric generation portion of the Company's
operations. The regulatory assets attributable to electric generation,
excluding balancing accounts which under existing conditions would be
expected to be recovered over the next few years, are estimated to be
$1.2 billion at June 30, 1994. This amount is based on the Company's
estimate of the allocation of these assets; the actual amount could
vary depending on the allocation methods adopted by the CPUC. The
amount of regulatory assets to be written off upon adoption of the
OIR/OII proposal could be substantially reduced depending on the
specific recovery provided during the transition to direct access.
Under the Company's OIR/OII proposal for the transition to direct
access, the Company indicated that it would increase Diablo Canyon's
depreciation expense by as much as $200 million annually. This
increase reflects the uncertainty about the economic life of Diablo
Canyon as a result of the OIR/OII. This change will not have an impact
on rates.
The CPUC's OIR/OII could impact the Company's recovery of its costs and
investments in electric utility assets, the Diablo Canyon rate case
settlement and continued application of SFAS No. 71. The final
determination of the impact will be dependent upon the form of
regulation, including transition mechanisms, if any, ultimately adopted
by the CPUC, and the effects of competition. The Company is unable to
predict the ultimate effect of the OIR/OII on its financial position or
results of operations.
The Company has been advised by its independent public accountants
that, if this matter has not been resolved prior to the completion of
their audit of the Company's financial statements for the year ending
December 31, 1994, their auditors' report on those financial statements
will include an explanatory paragraph relating to this contingency.
NOTE 3: REASONABLENESS PROCEEDINGS
- -----------------------------------
Recovery of energy costs through the Company's regulatory balancing
account mechanisms is subject to a CPUC determination that such costs
were incurred reasonably.
During reasonableness proceedings, the Division of Ratepayer Advocates
(DRA), a consumer advocacy branch of the CPUC staff, as well as other
groups (intervenors) may make recommendations to the CPUC. An
Administrative Law Judge (ALJ) will review testimony and issue a
proposed decision. Neither the DRA's recommendations nor the ALJ's
proposed decision constitutes a CPUC decision. The CPUC can accept
all, part or none of the recommendations or the ALJ's proposed decision
in its final decision. Under the current regulatory framework, annual
reasonableness proceedings are conducted by the CPUC on a historic
calendar year basis.
1988-1990: In March 1994, the CPUC issued decisions covering the years
1988 through 1990, ordering a disallowance of $90 million of gas costs,
plus accrued interest of approximately $25 million for the Company's
Canadian gas procurement activities, and $8 million for gas inventory
operations. The Company intends to contest the Canadian gas cost
disallowance and has filed an application for rehearing of that
decision.
The decision on the Company's Canadian gas procurement activities found
that the Company could have saved its customers money if it had
bargained more aggressively with its then-existing Canadian suppliers
or bought lower-priced gas from other Canadian sources. The CPUC
concluded that it was appropriate for the Company to take about 70
percent of its daily customer gas demand at the actual price charged
under its then-existing Canadian gas supply contracts, but that the
Company could have met the remainder of its daily demand with lower-
priced gas, either under those same contracts or with purchases from
other Canadian natural gas sources.
In its decision to disallow $8 million for gas inventory operations,
the CPUC found the Company's gas inventory operations during 1988
through 1990 to be reasonable except that the Company should have
withdrawn more gas from storage during December 1990 for use by the
Company's electric department.
CPUC consideration of other issues which relate to purchased electric
energy and certain contracts with Southwestern gas producers has been
deferred. With respect to purchased electric energy costs, the DRA
recommended a disallowance of $18 million for the Company's expenses
for purchased power from the Pacific Northwest. The Company purchased
electric energy when it was cheaper than its incremental fossil fuel
generation costs. The DRA argues that if cheaper Canadian gas supplies
had been used, the Company's incremental fossil fuel generation costs
would have been lower than the purchased power costs. The DRA also
indicated that it will be filing recommendations for the effects of any
imprudently incurred Canadian gas costs on the prices paid by the
Company for energy purchased from qualifying facilities (QFs) and
geothermal steam sources. The DRA has not yet addressed issues related
to certain contracts with Southwestern gas producers.
1991: The DRA issued a report on the reasonableness of the Company's
gas procurement and operating activities for 1991, which was modified
following the CPUC's decision on the 1988-1990 period. As modified in
June 1994, the DRA's report recommends that the Company refund $52
million related to Canadian gas purchases and $11 million related to
gas inventory operations and Southwestern gas procurement issues. A
final CPUC decision in this proceeding is expected later in 1994 or
early in 1995.
1992: The DRA issued a report on the reasonableness of the Company's
gas procurement and operating activities for 1992, which was modified
in June 1994, recommending a disallowance of $61 million. The
recommended disallowance includes $30 million related to Canadian gas
purchases and $8 million related to gas inventory operations. Also
included are disallowances totaling $23 million related to Southwest
gas transportation and procurement issues. It is possible that similar
issues will be raised regarding the Company's Canadian gas procurement
activities during 1993. However, because the market price of natural
gas increased in 1993, the Company estimates the disallowance that the
DRA may recommend for 1993 should be significantly lower than those for
prior years.
Affiliate Audit: In connection with the reasonableness proceeding for
1991, the DRA initiated an investigation of the operations of Alberta
and Southern Gas Co. Ltd. (A&S), a wholly owned gas purchasing
subsidiary of the Company, for 1988 through 1991. The DRA reviewed
certain nongas costs, primarily Canadian pipeline charges and A&S
overhead costs, and recommended a penalty of $50 million. The
recommended penalty is primarily related to the Company's alleged
failure to properly oversee its subsidiary's activities. A final CPUC
decision is not expected until later in 1994 or early 1995.
Recommendations related to 1992 activities may be made in a subsequent
report.
In addition, the DRA has indicated that it will be issuing a
supplemental report addressing matters relating to the Company's former
affiliate, Alberta Natural Gas Company (ANG) and the implications, if
any, of ANG's status as an affiliate of the Company. The DRA has noted
that a substantial portion of ANG's profits were derived from the
operation of the Cochrane liquids extraction plant and that the plant's
profitability contributed to the Company's pretax profit of $49 million
from the sale of its ANG shares in 1992.
Financial Impact of Reasonableness Proceedings: The Company believes
that its gas procurement activities, transportation arrangements and
operations were prudent and will vigorously contest any disallowance or
penalty recommended by the DRA or other parties.
The Company accrued $61 million in the fourth quarter of 1993 and
approximately $90 million in the first quarter of 1994 as a result of
the CPUC's disallowances in the gas reasonableness proceedings for 1988
through 1990 and the Company's assessment of how the CPUC's decisions
may impact the open reasonableness issues. However, the Company
intends to contest the CPUC's decision on the Canadian gas disallowance
for 1988 through 1990 and has filed an application for rehearing of
that decision.
The Company currently is unable to estimate the ultimate outcome of the
gas reasonableness proceedings, including the affiliate audit, or
predict whether such outcome will have a significant adverse impact on
its results of operations.
NOTE 4: CONTINGENCIES
- ----------------------
Helms Pumped Storage Plant (Helms):
- ----------------------------------
The Company has filed an application for rate recovery of the
remaining unrecovered Helms costs, the associated revenue requirement
on such costs since 1984 and lost revenues during the time the
generators were being repaired. The remaining net unrecovered costs
(after adjustment for depreciation) and revenues totaled $105 million
at June 30, 1994.
The Company has held discussions of possible settlement of these
issues with the DRA, but has not reached any conclusion.
The Company is uncertain whether, and to what extent any of the
remaining costs and revenues will be recovered through the ratemaking
process.
Nuclear Insurance:
- -----------------
The Company is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL I and II). If the nuclear plant of
a member utility is damaged or increased costs for business
interruption are incurred due to a prolonged accidental outage, the
Company may be subject to maximum assessments of $18 million
(property damage) or $7 million (business interruption), in each case
per policy period, if losses exceed premiums, reserves and other
resources of NML, NEIL I or NEIL II.
The federal government has enacted laws that require all utilities
with nuclear generating facilities to share in payment for claims
resulting from a nuclear incident. The Price-Anderson Act limits
industry liability for third-party claims resulting from any nuclear
incident to $9.2 billion per incident. Coverage of the first $200
million is provided by a pool of commercial insurers. If a nuclear
incident results in public liability claims in excess of $200
million, the Company 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 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 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 or sites used by the
Company 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 due to uncertainty concerning the
Company's responsibility, the complexity of environmental laws and
regulations, and the selection of compliance alternatives. However,
based on the information currently available, the Company has an
accrued liability as of June 30, 1994, of $62 million for hazardous
waste remediation costs. The ultimate amount of such costs may be
significantly higher if, among other things, the Company is held
responsible for cleanup at additional sites, other potentially
responsible parties are not financially able to contribute to these
costs, or further investigation indicates that the extent of
contamination and affected natural resources is greater than
anticipated at sites for which the Company is responsible.
The Company believes that the ultimate outcome of these matters will
not have a significant adverse impact on its financial position or
results of operations.
Legal Matters:
- -------------
Stanislaus Litigation: In December 1993, the County of Stanislaus,
California, and a residential customer of PG&E, filed a complaint
against PG&E and Pacific Gas Transmission Company, a subsidiary of
the Company, on behalf of themselves and purportedly as a class
action on behalf of all natural gas customers of PG&E, for the period
of February 1988 through October 1993. The complaint alleges that
the purchase of natural gas in Canada by A&S was accomplished in
violation of various antitrust laws which resulted in increased
prices of natural gas for PG&E's customers.
The complaint alleges that the Company could have purchased as much
as 50 percent of its Canadian gas on the spot market instead of
relying on long-term contracts and that the damage to the class
members is at least as much as the price differential multiplied by
the replacement volume of gas, an amount estimated in the complaint
as potentially exceeding $800 million. The complaint indicates that
the damages to the class could include over $150 million paid by the
Company to terminate the contracts with the Canadian gas producers in
November 1993. The complaint also seeks recovery of three times the
amount of the actual damages pursuant to antitrust laws.
The Company believes the case is without merit and has filed a motion
to dismiss the complaint. The Company believes that the ultimate
outcome will not have a significant adverse impact on its financial
position.
Hinkley Litigation: In 1993, a complaint was filed in San Bernardino
County 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
the Company'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 the Company discharged chromium-
contaminated wastewater into unlined ponds, which led to chromium
percolating into the groundwater of surrounding property. The
plaintiffs further allege that the Company discharged the chromium
into those ponds to avoid costly alternatives.
In 1987, the Company undertook an extensive project to remediate
potential groundwater chromium contamination. The Company has
incurred substantially all of the costs it currently deems necessary
to clean up the affected groundwater contamination. In accordance
with the remediation plan approved by the regional water quality
control board, the Company will continue to monitor the affected area
and periodically perform environmental assessments.
In November 1993, the parties engaged in private mediation sessions.
Since then, plaintiffs' counsel has offered to compromise and
settle plaintiffs' claims against the Company for $265 million.
However, that amount related to the claims of only approximately two-
thirds of the presently known plaintiffs. There have been subsequent
mediation sessions but no resolution has been reached and discussions
continue.
The Company is unable to estimate the ultimate outcome of this
matter, but such outcome could have a significant adverse impact on
the Company's results of operations. The Company believes that the
ultimate outcome of this matter will not have a significant adverse
impact on its financial position.
QF Transmission Constrained Area Litigation: In July 1994, the
Company settled a lawsuit resulting from the termination of a power
purchase agreement. The settlement did not have a significant impact
on the Company's financial position or results of operations.
County Franchise Fees Litigation: In March 1994, Santa Clara and
Alameda counties filed a class action suit against the Company on
behalf of themselves and 45 other counties in the Company's service
area. This lawsuit alleges that the Company underpaid franchise fees
to the counties for the right to use or occupy public streets or
roads as a result of incorrectly computing these payments. Should
the counties prevail, the amount of damages for alleged underpayments
for the years 1987 through 1993 could be as high as $127 million,
including interest, as of June 30, 1994. The Company believes that
the ultimate outcome will not have a significant adverse impact on
its financial position or results of operations.
City Franchise Fees Litigation: In May 1994, the City of Santa Cruz
filed a class action suit against the Company on behalf of itself and
106 other cities in the Company's service area. The complaint
alleges that the Company has improperly underpaid electric franchise
fees to the cities by calculating fees at different rates from other
cities. Should the cities prevail, the amount of damages for alleged
underpayments for the years 1987 through 1993 could be as high as
$117 million, including interest, as of June 30, 1994. The Company
believes that the ultimate outcome will not have a significant
adverse impact on its financial position or results of operations.
Item 2. Management's Discussion and Analysis of Consolidated
----------------------------------------------------
Results of Operations and Financial Condition
---------------------------------------------
RESULTS OF OPERATIONS
- ---------------------
Pacific Gas and Electric Company (PG&E) and its wholly owned and
majority-owned subsidiaries (collectively, the Company) have three
types of operations: utility, Diablo Canyon Nuclear Power Plant
(Diablo Canyon) and nonregulated through PG&E Enterprises
(Enterprises). For the six months ended June 30, 1994 and 1993,
selected financial information for the three types of operations is
shown below:
- ----------------------------------------------------------------------------------------------------
Utility Diablo Canyon Enterprises Total
(in millions, except -------------- ------------- ------------ --------------
per share amounts) 1994 1993 1994 1993 1994 1993 1994 1993
- ----------------------------------------------------------------------------------------------------
THREE MONTHS ENDED
JUNE 30
Operating revenues
Electric $ 1,506 $ 1,376 $ 398 $ 454 $ - $ - $ 1,904 $ 1,830
Gas 483 570 - - 53 64 536 634
------- ------- ------ ------ ----- ----- ------- -------
Total operating revenues 1,989 1,946 398 454 53 64 2,440 2,464
Operating expenses 1,709 1,716 279 294 56 66 2,044 2,076
------- ------- ------ ------ ----- ----- ------- -------
Operating income (loss) $ 280 $ 230 $ 119 $ 160 $ (3) $ (2) $ 396 $ 388
======= ======= ====== ====== ===== ===== ======= =======
Net income (loss) $ 174 $ 125 $ 80 $ 111 $ (13) $ 9 $ 241 $ 245
Earnings (loss) per common share $ .38 $ .26 $ .18 $ .25 $(.03) $ .02 $ .53 $ .53
SIX MONTHS ENDED
JUNE 30
Operating revenues
Electric $ 2,887 $ 2,716 $ 833 $ 836 $ - $ - $ 3,720 $ 3,552
Gas 1,127 1,254 - - 107 122 1,234 1,376
------- ------- ------ ------ ----- ----- ------- -------
Total operating revenues 4,014 3,970 833 836 107 122 4,954 4,928
Operating expenses 3,450 3,447 582 553 112 120 4,144 4,120
------- ------- ------ ------ ----- ----- ------- -------
Operating income (loss) $ 564 $ 523 $ 251 $ 283 $ (5) $ 2 $ 810 $ 808
======= ======= ====== ====== ===== ===== ======= =======
Net income (loss) $ 315 $ 299 $ 176 $ 185 $ (13) $ 17 $ 478 $ 501
Earnings (loss) per common share $ .69 $ .64 $ .39 $ .41 $(.03) $ .04 $ 1.05 $ 1.09
Total assets at June 30 $19,926 $19,021 $6,131 $6,327 $1,165 $1,005 $27,222 $26,353
- ----------------------------------------------------------------------------------------------------
Earnings Per Common Share:
- -------------------------
The Company's earnings per common share for the three months ended
June 30, 1994, remained unchanged from the comparable period of 1993,
resulting from lower costs in 1994 as a result of the Company's
workforce reduction program implemented in 1993, that were partially
offset by an increase in litigation reserves and a loss associated
with Enterprises' sale of several oil and gas properties as discussed
in the Sales and Acquisition section below. The Company's earnings
per share for 1993 reflected proceeds received by Enterprises
resulting from the termination of a power sales agreement. In
addition, Diablo Canyon operated at a lower capacity factor in the
second quarter of 1994 due to both scheduled and unscheduled outages.
The Company's earnings per common share for the six months ended June
30, 1994, were lower than for the comparable period of 1993 primarily
due to higher expenses related to gas matters, an increase in
litigation reserves and a loss associated with Enterprises' sale of
several oil and gas properties. These higher expenses were offset by
lower costs resulting from the workforce reduction program implemented
in 1993. As discussed above, the Company's earnings per common share
for 1993 reflected proceeds received by Enterprises. As discussed
below, Diablo Canyon operated at a lower capacity factor for the six
months ended June 30, 1994.
Common Stock Dividend:
- ---------------------
The Company's common stock dividend is based on a number of financial
considerations, including sustainability, financial flexibility and
competitiveness with investment opportunities of similar risk. Over
time, the Company plans to reduce its dividend payout ratio (dividends
declared divided by earnings available for common stock) to between 50
and 65 percent (based on earnings exclusive of nonrecurring
adjustments) to reflect the increased business risk in the utility
industry and the earnings volatility associated with the Diablo Canyon
rate case settlement.
At this time, the Company is unable to determine the impact, if any,
the proposed restructuring of the electric industry in California will
have on the Company's ability to increase its dividends in the future .
The ultimate impact will depend on the final form of the restructuring
when it is implemented.
Operating Revenues:
- ------------------
Electric revenues for the three and six months ended June 30, 1994,
increased compared with the same periods of 1993 primarily due to an
increase in revenues related to electric energy costs in 1994 which
was partially offset by a decrease in Diablo Canyon revenues as
discussed above.
Gas revenues for the three and six months ended June 30, 1994,
decreased compared with the same periods of 1993, primarily due to a
decrease in revenues received from noncore customers. Beginning in
the latter half of 1993, the implementation of regulatory changes has
allowed many of the Company's noncore customers to arrange for the
purchase of their own gas supplies, with the Company providing
transportation service for these noncore customers.
Operating Expenses:
- ------------------
The changes in operating expenses for the three and six months ended
June 30, 1994, compared with the same periods of 1993, were due to
lower expenses related to the Company's 1993 workforce reduction
program and a decrease in the cost of gas due to the Company no
longer procuring gas for noncore customers, as discussed above. This
decrease was offset by an increase in the cost of electric energy as
a result of less favorable hydroelectric conditions. This increase
in the cost of electric energy also reflects an increase in the cost
per kilowatthour (kWh) for purchased power and an increase in the
volume of gas used to provide electric energy.
Diablo Canyon:
- -------------
The Diablo Canyon plant capacity factors for the six months ended June
30, 1994 and 1993, were 75 percent and 80 percent, respectively,
reflecting the scheduled refueling outage for Unit 1 in 1994 and for
Unit 2 in 1993. The 1994 capacity factors were also impacted by
approximately 24 days of extended unscheduled outages during the six
months ended June 30, 1994, due to two minor nonnuclear problems.
There were no extended unscheduled outages during the six months ended
June 30, 1993. Through June 30, 1994, the lifetime capacity factor for
the plant was 79 percent. The Diablo Canyon rate case settlement bases
revenues primarily on the amount of electricity generated by the plant,
rather than on traditional cost-based ratemaking. Each Diablo Canyon
unit will contribute approximately $3.1 million in revenues per day at
full operating power in 1994.
Changing Competitive and Regulatory Environment:
- -----------------------------------------------
Competitive and regulatory changes in the Company's gas and electric
businesses are occurring at an ever increasing rate. In particular,
there is increasing pressure on the Company to provide its largest
electric and gas customers with competitive prices. In April 1994, the
California Public Utilities Commission (CPUC) issued a proposal on
electric industry restructuring which seeks to put downward pressure on
prices, and enhance California's competitiveness by changing from
traditional cost-based ratemaking to performance-based ratemaking,
unbundling electric service and phasing-in retail wheeling over a six-
year period beginning in 1996. Meanwhile, the Company has made several
proposals to modify regulatory processes and to provide additional
pricing flexibility to those customers with the most competitive
options. These proposals are discussed below under the CPUC Electric
Industry Restructuring Proposal, Regulatory Reform Initiative (RRI) and
Long-Term Noncore Gas Transportation Prices sections.
CPUC Electric Industry Restructuring Proposal: In April 1994, the CPUC
issued an order instituting a rulemaking and an investigation (OIR/OII)
on electric industry restructuring. The OIR/OII follows a report
issued by the CPUC's Division of Strategic Planning in February 1993,
which concluded that the current regulatory approach is incompatible
with the emerging industry structure resulting from technological
change, increasing competitive pressure and new market forces.
The CPUC's proposal, which is subject to comment and modification,
involves two major changes in electric industry regulation. The first
would move electric utilities from traditional cost-of-service rate
cases to performance-based ratemaking (PBR) in order to provide
stronger incentives for efficient utility operations, management and
investment. The CPUC indicated that the ongoing energy utility PBR
application proceedings, including the Company's RRI, would be used to
develop programs which may vary in detail among the utilities.
The second major change proposed in the OIR/OII would unbundle electric
services and require the phase-in of direct access by electric utility
retail customers to a range of electric generation providers, including
utilities, over a six-year period from 1996 to 2002. After the
unbundling of electric services, the utility serving a given territory
would still be obligated to provide transmission and distribution
services on a nondiscriminatory basis to customers choosing direct
access service from another provider. This concept is commonly
referred to as retail wheeling. Coinciding with these changes, the
CPUC foresees development of a competitive spot market for electric
generation and an increasing need for inter-regional coordination of
the electric grid. Existing resource planning and procurement
approaches would be abolished. In addition, the Electric Revenue
Adjustment Mechanism (ERAM) and other balancing account mechanisms
would be discontinued for direct access customers.
Under the CPUC's proposal, direct access to generation for the
Company's industrial customers, representing 16 percent of total retail
electric revenue, would be phased in over a three-year period beginning
in January 1996. Commercial customers, representing 39 percent of
total retail electric revenue, would have direct access beginning in
January 1999. All remaining customers (primarily residential),
representing 45 percent of total retail electric revenue, would have
direct access beginning in January 2002.
With respect to electric services, the CPUC would open at least two
investigation proceedings to examine (1) the potential for and cost
allocations of any uneconomic utility generating assets, and (2)
unbundling and pricing of utility services for direct access. Under
the CPUC's proposal, the utility would remain the provider of last
resort for all customers. Direct access customers who purchase
electricity from another source would continue to secure services from
utilities, including distribution, transmission, system control and
coordination, and other required services. Utilities would be given
the pricing flexibility to compete effectively for direct access
customers. Prices negotiated between the utility and direct access
customers could not exceed the tariffed rate or fall below the
utility's marginal cost of providing the service. The CPUC proposed
that discounts given to direct access customers would be absorbed by
the utility's shareholders.
To ensure an orderly transition that maintains the financial integrity
of the utilities, the CPUC proposed that stranded costs of utility
generating assets be recovered through a "competition transition
charge." All consumers, including direct access consumers, would
contribute to recovery of these transition costs. To the extent that
uneconomic costs are passed on to all ratepayers through a transition
mechanism, the CPUC proposed not to allow any customer class' overall
allocation of generation costs or amortization schedules to exceed
current levels, in order to avoid a shift of those costs among customer
classes or across generations of customers. The OIR/OII stated that
utilities would not be at risk for recovery of the uneconomic portion
of the utilities' generating assets. The CPUC's investigation into
uneconomic generating assets will include consideration of any costs
relating to existing utility obligations under certain electric
purchase contracts as well as long-term fuel contracts. The Diablo
Canyon rate case settlement is not specifically addressed in the
OIR/OII.
In June 1994, the Company filed its initial comments on the CPUC's
proposal. In its comments, the Company indicated that it shares the
CPUC's goal of effecting the transition to a more competitive world in
a manner which would: (1) achieve competitive electric prices for
consumers; (2) maintain utilities' financial integrity; (3) sustain an
electric supply system which provides reliable service for all
Californians; (4) avoid shifting of costs from one group of customers
to another (in particular, to residential customers); and (5) allow
continuation of California's environmental and social benefit programs.
The Company noted that to achieve these objectives, the CPUC must
resolve fundamental legal, jurisdictional and public policy issues and
obtain the approval of the Federal Energy Regulatory Commission and the
California State Legislature (Legislature). The Company's proposal in
response to the CPUC OIR/OII includes the following key elements:
(1) Implementation Schedule: The Company proposed an implementation
schedule that would allow all electric power consumers access to a
retail electric power marketplace by January 1, 2008. Direct access
would commence as proposed by the CPUC on January 1, 1996, but for a
more limited set of large customers receiving service at transmission
voltage levels. Each year, additional groups of customers would be
included in the direct access category.
Industrial and large commercial customers which would be eligible in
the period 1996 through 2002 represent approximately 23 percent of
total retail electric revenue. The remaining nonresidential customers,
which would be eligible in the period 2003 through 2006, represent
approximately 38 percent of total retail electric revenue. Residential
customers would be eligible in 2007 and 2008 and represent
approximately 39 percent of total retail electric revenue. If the
Company's proposed implementation schedule is adopted, it will request
recovery of certain incurred and committed costs through the transition
charge, but will not request recovery of transition costs associated
with its electric generation facilities. The Company indicated that
its proposed schedule, coupled with pricing flexibility, will permit
the Company sufficient time to reduce its generation costs and recover
its investments in facilities.
(2) Transition Costs: The Company identified three main categories of
potential transition costs described below. The Company's proposal
dealt with these costs in two ways: by allowing sufficient time to
reduce the amount of transition costs, and by imposing transition
charges which must be paid by all customers.
(i) Ongoing costs associated with utility-owned generation facilities:
If the Company's proposals are adopted in their entirety, the Company
would accept the full market risk of recovery of the ongoing costs of
its generation facilities, including Diablo Canyon under the pricing
formula in the rate case settlement, whether due to discounted prices
or lost sales.
Under the Company's OIR/OII proposal for the transition to direct
access, the Company indicated that it would increase Diablo Canyon's
depreciation expense by as much as $200 million annually. This
increase reflects the uncertainty about the economic life of Diablo
Canyon as a result of the OIR/OII. This change will not have an impact
on rates.
(ii) Ongoing costs associated with above-market payments under
qualifying facilities (QFs) power purchase agreements: The Company
purchases approximately 20 percent of its generation from QFs under
long-term agreements mandated or approved by the CPUC, some of which
result in payments above current market levels. The Company indicated
that the uneconomic portion of the energy and capacity payments
provided under these agreements should be included in a transition
charge borne by all customers interconnected to the system. The
Company estimates that in 1994 it will pay approximately $800 million
over current market levels for these purchases. The Company is
attempting to buyout or restructure certain fixed-price QF contracts in
order to reduce purchased power costs.
(iii) Costs and obligations incurred in the past under traditional
cost-of-service regulation: The Company proposed transition cost
recovery for existing regulatory assets and certain other costs and
obligations arising out of historic utility activities related to
electric generation. These assets and costs include the unamortized
balancing accounts related to the Energy Cost Adjustment Clause (ECAC)
and the ERAM, the unamortized premium on reacquired debt, utility
deferred taxes, workers' compensation and disability claims, pension
costs, environmental mitigation costs associated with existing and
retired electric plants, and post-retirement benefits other than
pensions.
(3) Pricing Flexibility and Market Risk for Utility Electric Power
Sales: The Company would continue to provide full retail service at
regulated rates to full-service customers. For direct access
customers, the Company proposed that it be able to compete to sell them
unbundled electric power, in a way that insulates full-service
customers from any lost contribution to margin, whether due to reduced
prices or lost sales. When direct access to generation is available to
all customers, the Company should be free to use its generation
resources, including power purchase arrangements, in the competitive
marketplace as it sees fit.
(4) Environmental and Social Programs: The Company proposed that none
of the existing environmental and social programs should be
discontinued because of a move to direct access. Unless and until a
policy decision is made to discontinue a program, costs should be
allocated to all electric customers, including those who elect direct
access.
(5) Obligation to Serve: For the foreseeable future, the Company
proposed to retain an ongoing obligation to provide electric power for
residential customers, but proposed that the utility should be
obligated to provide electric supply only on a best-efforts basis to
nonresidential direct access customers that decide to return to the
Company for their power supply.
Currently, the CPUC is conducting hearings to receive parties' comments
on its proposal. The CPUC has indicated that it anticipates adopting a
final policy statement no earlier than October 1994. The two companion
investigations described above are scheduled to be completed by June
1995 so that eligible customers may commence direct access service in
January 1996. The CPUC will open a further investigation in July 1996
to assess the direct access program and to determine whether and how to
expand eligibility to other customers.
In addition, it appears likely that the Legislature will pass a
resolution in August 1994 requesting that the CPUC not take any action
to implement electric utility restructuring until it has first reported
to the Legislature the details of that restructuring. The report would
be due no later than January 31, 1995.
RRI: In March 1994, the Company filed an application with the CPUC
requesting that it adopt the Company's proposed RRI and approve 1995
electric and gas base revenue requirements. The Company's proposal is
the result of discussions with the CPUC, customers and other interested
parties concerning various reforms to the current regulatory approach
to setting rates. While the guiding principles behind the Company's
RRI proposal are not affected by the OIR/OII, many of the specifics
would change. Once the CPUC's electric industry restructuring plan is
firm enough to allow it, the Company proposes to revise its RRI filing
to reflect direct access, which would be effective January 1, 1996.
As filed, the Company's RRI has three components: (1) PBR for
determining base revenues; (2) establishment of a large electric
manufacturing class (LEMC) of customers; and (3) use of market
benchmarks to evaluate gas procurement costs. Specific proposals
regarding the third component were not included in the Company's March
1994 filing but are expected to be filed at a later date. As part of
its response to the OIR/OII, the Company proposed that a set of
competitive pricing options be established for large electric
customers. These options would replace the proposal for the LEMC,
since these customers would be permitted direct access in the initial
years upon implementation of the OIR/OII. Accordingly, the Company
intends to eliminate its LEMC proposal when it refiles the RRI.
Under the Company's PBR proposal, electric and natural gas base
revenues would be determined annually by formula rather than through
General Rate Cases, Attrition Rate Adjustments (ARAs) and Cost of
Capital proceedings. Base revenues are intended to recover the
Company's nonfuel costs and provide a return on invested capital.
The PBR mechanism would not apply to the base revenue associated with
Diablo Canyon, including Diablo Canyon decommissioning costs, which
would continue to be determined pursuant to the Diablo Canyon rate case
settlement. Revenues to offset fuel and fuel-related costs would still
be determined in the ECAC proceeding for electric operations and the
Biennial Cost Allocation Proceeding (BCAP) for gas operations.
The Company's proposed PBR mechanism would determine the base revenues
by multiplying the base revenues authorized for the prior year by an
index consisting of inflation plus customer growth less a productivity
factor. Those revenues would be adjusted up or down depending on the
Company's achievement relative to four performance standards: Customer
Energy Efficiency (CEE) programs, Energy Bills, Customer Satisfaction
and Electric Service Reliability. The adjustments related to the
Company's performance in these four areas would be one-time
modifications to that year's base revenues. The adjustments for CEE
incentives would be determined under existing ratemaking procedures.
The maximum adjustment that the Company could earn or lose related to
Energy Bills and Customer Satisfaction is $25 million per year for
each, and the maximum for Electric Service Reliability is $19 million
per year. Under PBR, the Company could also apply for an adjustment to
base revenues due to the occurrence of certain extraordinary events
outside the Company's control.
The PBR proposal provides for the sharing between ratepayers and
shareholders of earnings above or below a target utility return on
equity (ROE) that would be computed annually. To the extent actual ROE
varies more than 200 basis points above or below the target ROE, the
difference would be shared equally between ratepayers and shareholders
through a reduction or increase in the next year's base revenue. If
actual ROE were more than 500 basis points above or below the target
ROE, then the Company and the CPUC would each have the option to
initiate a proceeding to reexamine the PBR formula.
As filed, the Company proposed that PBR base revenue indexing begin in
1995. However, this requested implementation date has been superseded
by the Company's proposed 1995 Electric Rate Stabilization program,
described below in the Rate Matters section. Currently, it is not
anticipated that rates set by PBR will be effective until January 1997.
In its filing, the Company proposed that PBR remain in place
indefinitely. The Company recommended that after five years the CPUC
review the PBR mechanism and make any necessary adjustments, but not
return to the use of traditional rate cases to set rates.
Long-Term Noncore Gas Transportation Prices: In June 1994, the Company
filed a petition with the CPUC to modify the decision that established
the Expedited Application Docket (EAD), the existing competitive gas
transportation contract procedure. The petition requested
authorization to implement an optional long-term noncore gas
transportation price which would be offered to the Company's largest
industrial and cogeneration gas transport customers under a ten-year
service agreement.
The proposed prices are intended to enable the Company to more
effectively meet intensified competition by allowing it to offer a
long-term competitive price without having to obtain CPUC approval on a
contract-by-contract basis as is currently required under the EAD
procedure.
The proposed prices are within the range of prices negotiated under
existing EAD contracts and would exceed the marginal cost of serving
the customers eligible for the new prices. The Company's shareholders
would bear the risk of any revenue shortfalls attributable to
differences between the long-term price option and the customer's
otherwise applicable standard price. If approved, the prices would be
offered to existing qualifying customers over a two-month subscription
period commencing on the date designated by the CPUC. A CPUC decision
is expected later this year.
Financial Impact of the Changing Competitive and Regulatory
Environment: Based on the regulatory framework in which it operates,
the Company currently accounts for the economic effects of regulation
in accordance with the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." As a result of applying the provisions of SFAS No. 71,
the Company has accumulated approximately $3.5 billion of regulatory
assets, including balancing accounts, as of June 30, 1994.
In the event that recovery of specific costs through rates becomes
unlikely or uncertain for all or a portion of the Company's utility
operations, whether resulting from the expanding effects of competition
or specific regulatory actions which move the Company away from cost-
of-service ratemaking, SFAS No. 71 would no longer apply.
Discontinuation of SFAS No. 71 would cause the write off of applicable
portions of regulatory assets, which could have a significant adverse
impact on the Company's financial position or results of operations.
If the OIR/OII is adopted it would impact the future application of
SFAS No. 71 for the electric generation portion of the Company's
operations. The regulatory assets attributable to electric generation,
excluding balancing accounts which under existing conditions would be
expected to be recovered over the next few years, are estimated to be
$1.2 billion at June 30, 1994. This amount is based on the Company's
estimate of the allocation of these assets; the actual amount could
vary depending on the allocation methods adopted by the CPUC. The
amount of regulatory assets to be written off upon adoption of the
OIR/OII proposal could be substantially reduced depending on the
specific recovery provided during the transition to direct access.
Under the Company's OIR/OII proposal for the transition to direct
access, the Company indicated that it would increase Diablo Canyon's
depreciation expense by as much as $200 million annually. This
increase reflects the uncertainty about the economic life of Diablo
Canyon as a result of the OIR/OII. This change will not have an impact
on rates.
The CPUC's OIR/OII could impact the Company's recovery of its costs and
investments in electric utility assets, the Diablo Canyon rate case
settlement and continued application of SFAS No. 71. The final
determination of the impact will be dependent upon the form of
regulation, including transition mechanisms, if any, ultimately adopted
by the CPUC, and the effects of competition. The Company is unable to
predict the ultimate effect of the OIR/OII on its financial position or
results of operations.
It is anticipated that as proposed, the PBR component of the RRI will
act as a surrogate for traditional cost-of-service ratemaking. As
such, the Company expects it would continue to apply SFAS No. 71 to the
majority of its electric and gas operations. However, the Company may
be subject to additional write-offs attributable to those regulatory
mechanisms proposed to be discontinued as part of the RRI.
If the long-term noncore gas transportation pricing is adopted as
proposed, it would deviate from cost-of-service ratemaking and the
Company would discontinue application of SFAS No. 71 for customers
receiving the new rates. The resulting write-off upon discontinuation
of SFAS No. 71 for these customers is currently estimated at $25
million pretax. The estimated amount related to the affected gas
customers is based on the base revenue allocation currently used in
setting rates; the actual amount could vary depending on the allocation
method adopted by the CPUC.
The Company may be subject to additional write-offs even though SFAS
No. 71 continues to apply to remaining portions of the Company's
operations. Additional write-offs could result from regulatory actions
affecting recovery of specific regulatory assets.
Rate Matters:
- ------------
In addition to the RRI and the long-term noncore gas transportation
price proposals discussed above, the following are other rate-related
matters.
1995 Electric Rate Stabilization: In August 1994, the Company
announced that it will extend its freeze on retail electric rates
through the end of 1995. The electric rate freeze extension is
dependent upon the CPUC's adoption of certain rate changes requested by
the Company for 1995. As previously disclosed, in April 1993, the
Company had adopted a freeze on electric rates through the end of 1994.
The Company also will continue its annual $70 million economic stimulus
rate reduction through 1995 for its largest business customers. The
reduction, begun in July 1993, was developed to help attract and retain
major employers in Northern and Central California. The electric rate
freeze extension and the continuation of the economic stimulus rate
represent further steps in the Company's efforts to improve its ability
to succeed in the face of greater competition.
The Company also announced that when it files its 1996 General Rate
Case (GRC) later this year, it will not seek an increase in 1996
electric base revenues from 1994 levels attributable to its expenses
other than fuel, purchased power and Diablo Canyon costs.
To accomplish the electric rate freeze extension, the Company
anticipates that it will forgo electric rate increases that otherwise
would occur on January 1, 1995, under the ARA mechanism. These
increases had previously been authorized by the CPUC in the Company's
1993 GRC.
If the CPUC adopts the Company's requests in the ECAC and 1995 Cost of
Capital proceedings (see the ECAC and Cost of Capital discussions
below), combined net electric revenue requirement would increase by an
estimated $289 million, effective January 1, 1995. To the extent that
the CPUC grants these electric revenue requirement increases, the
Company anticipates that it will request a corresponding decrease in
base revenues under the ARA mechanism, such that electric rates will
not increase through the end of 1995. The Company intends to offset
any such required decrease in base revenues through cost reductions.
To the extent that these cost reductions are not achieved, there may be
a negative impact on the Company's 1995 or 1996 results of operations.
ECAC: In the 1993 ECAC decision, the CPUC approved the Company's
request to defer beyond 1994 $255 million of estimated undercollections
in the ECAC/ERAM balancing accounts. The actual ECAC/ERAM net
undercollection at December 31, 1993, was $525 million. With the
stated objective of providing additional incentives for cost
containment, the CPUC refused to allow the Company to collect interest
on the revenue requirement deferral and ordered the reinstatement of
the Annual Energy Rate (AER) mechanism. The reinstatement of the AER
places the Company at risk for nine percent of the variations between
actual and forecasted energy expenses.
The Company's current ECAC application requests a two percent increase
($158 million) in electric revenues over rates in effect in 1994. The
Company's proposal limits the requested recovery of the projected
December 31, 1994, ECAC undercollection of $537 million by deferring
recovery of $368 million beyond 1995. The filing also proposes to
forgo collection of interest on the ECAC deferral.
In July 1994, the Division of Ratepayer Advocates (DRA), a consumer
advocacy branch of the CPUC staff, issued a report on the Company's
filing. The DRA's revenue requirement proposal is approximately $110
million lower than the Company's request due primarily to the DRA's
lower gas cost estimates and Diablo Canyon price assumptions. The DRA
also recommends that the Company's rates remain frozen at the 1994
level through 1995 and that the ECAC undercollection be deferred,
without interest, beyond 1995.
In its report, the DRA asserted that the Company has failed to take
actions in response to concerns about the Company's high electricity
rates. The DRA proposed that the CPUC reconsider a consumer advocacy
group's 1992 petition and reopen the Diablo Canyon rate case settlement
(settlement) for the express purpose of modifying the payment
methodology for Diablo Canyon generation. The CPUC had previously
denied this petition finding that there had been no failure in the
underlying assumptions of the settlement and that reopening it would be
contrary to the public policy in favor of settlements.
In addition, the DRA recommended that in the interim, while the payment
methodology is being reconsidered, the price paid for electricity
generated by Diablo Canyon be frozen at the 1994 price level of 11.89
cents per kWh which would result in a $35 million reduction in the
Company's 1995 revenue requirement request. The Company's filing
included an increase in the price paid for Diablo Canyon generation to
12.10 cents per kWh in 1995, using the pricing formula set forth in the
settlement.
Based on its claim that the Company has failed to propose methods or
take action to reduce rates, the DRA urged the CPUC to consider the
possibility of eliminating or reducing the ratepayers' obligation to
pay for deferred ECAC costs at some future date. If the CPUC acts on
this aspect of the DRA's request, the Company may be precluded from
recording additional ECAC costs and may also be required to write off
portions of the existing ECAC balance. However, the Company believes
that under existing conditions, it will recover the ECAC
undercollection over the next few years.
In July 1994, the Company filed a motion requesting the CPUC to remove
the Diablo Canyon testimony from the DRA's report on the basis that it
is contrary to previous CPUC decisions which uphold the settlement, is
factually incorrect, and violates the CPUC's policy in favor of
comprehensive settlements. In August, the Company filed rebuttal
testimony in the ECAC proceeding, reiterating that the DRA's report
violates the public policy in favor of settlements. The Company also
pointed out that, contrary to the DRA's report, under the ratemaking
methodology employed by the DRA in the proceeding in which the
settlement was established, the Company in fact has recovered $2.5
billion less than it would have under traditional ratemaking. The
Company also noted that the risk of future performance of the plant
remains with the Company. A decision is expected in December 1994.
BCAP: In July 1994, the CPUC approved the Company's request for an
increase of $162 million (9.3 percent) in core (residential and smaller
commercial customers) rates effective July 15, 1994. During the first
half of the current BCAP period, actual gas costs were higher than the
forecasted costs used to adopt rates and actual gas sales were less
than expected, leading to unrecovered gas and related fixed costs. The
$162 million BCAP increase is expected to recover such costs by July
1995.
Cost of Capital: In May 1994, the Company filed an application with
the CPUC in the 1995 Cost of Capital proceeding requesting the
following:
Utility
Capital Weighted
Structure Cost/Return Cost
Common equity 48.00% 12.50% 6.00%
Preferred stock 5.50 8.12 .45
Long-term debt 46.50 7.53 3.50
----- ----- ----
Total requested return
on average utility
rate base 9.95%
====
The requested return on common equity and common equity ratio is an
increase from the 11.00 percent and 47.50 percent, respectively,
authorized in 1994. These increases reflect higher interest rates and
increased regulatory and competitive risks. An additional 75 basis
points was included in the Company's requested return on common equity
in order to address, in particular, the added risks associated with the
CPUC's proposed OIR/OII on electric industry restructuring. If
adopted, the Company's request would result in annual revenue
requirement increases of $131 million for electric rates and $41
million for gas rates, effective January 1995.
In August 1994, the DRA issued its report on the Company's 1995 Cost of
Capital proceeding recommending a return on common equity of 11.25
percent and an overall return on utility rate base of 9.36 percent.
The DRA also recommended a utility capital structure of 48.00 percent
common equity, 5.50 percent preferred stock and 46.50 percent long-term
debt. If adopted, the DRA's recommendation would result in annual
revenue requirement increases of $28 million for electric rates and $9
million for gas rates, effective January 1995. A final CPUC decision
is expected in the fourth quarter of 1994.
1996 GRC: Although the Company's RRI filing and the CPUC's OIR/OII on
electric industry restructuring may eliminate the need for hearings on
the 1996 GRC, the Company is continuing its preparation of the 1996 GRC
with the expectation that the RRI and OIR/OII will run parallel with
its 1996 GRC.
The Company intends to file its 1996 GRC application before the end of
1994, for rates effective January 1, 1996. As currently contemplated,
there would be no increase in 1996 electric base revenues from 1994
levels attributable to expenses other than fuel, purchased power and
Diablo Canyon costs, and a minimal decrease from current gas base
revenues.
Reasonableness Proceedings:
- --------------------------
The CPUC reviews the reasonableness of the Company's energy costs on an
annual basis. As part of this review, recommendations may be made by
the DRA as well as intervenors. An Administrative Law Judge (ALJ) of
the CPUC will review testimony and issue a proposed decision. The CPUC
can accept all, part or none of the recommendations or the ALJ's
proposed decision in its final decision.
In March 1994, the CPUC issued decisions covering the years 1988
through 1990, ordering a disallowance of $90 million of gas costs, plus
accrued interest of approximately $25 million for the Company's
Canadian gas procurement activities and $8 million for gas inventory
operations. The Company intends to contest the Canadian gas cost
disallowance and has filed an application for rehearing of that
decision.
As discussed in Note 3 of Notes to Consolidated Financial Statements, a
number of reasonableness issues are still under review by the CPUC,
including an audit of the Company's affiliates. The DRA has
recommended disallowances and a penalty totaling at least $192 million
for various issues covering 1988 through 1992 and has indicated it may
be submitting additional recommendations for these years.
The Company believes that its gas procurement activities,
transportation arrangements and operations were prudent and will
vigorously contest any disallowance or penalty recommended by the DRA
or other parties.
The Company accrued $61 million in the fourth quarter of 1993 and
approximately $90 million in the first quarter of 1994 as a result of
the CPUC's disallowances in the gas reasonableness proceedings for 1988
through 1990 and the Company's assessment of how the CPUC's decisions
may impact the open reasonableness issues. However, as discussed
above, the Company intends to contest the CPUC's decision on the
Canadian gas disallowance for 1988 through 1990.
The Company currently is unable to estimate the ultimate outcome of the
gas reasonableness proceedings, including the affiliate audit, or
predict whether such outcome will have a significant adverse impact on
its results of operations.
Legal Matters:
- -------------
Stanislaus Litigation: In December 1993, the County of Stanislaus,
California and a residential customer of PG&E, filed a complaint
against PG&E and Pacific Gas Transmission Company, a subsidiary of
the Company, on behalf of themselves and purportedly as a class
action on behalf of all natural gas customers of PG&E for the period
of February 1988 through October 1993. The complaint alleges that
the purchase of natural gas in Canada by A&S was accomplished in
violation of various antitrust laws which resulted in increased
prices of natural gas for PG&E's customers.
The complaint alleges that the Company could have purchased as much
as 50 percent of its Canadian gas on the spot market instead of
relying on long-term contracts and that the damage to the class
members is at least as much as the price differential multiplied by
the replacement volume of gas, an amount estimated in the complaint
as potentially exceeding $800 million. The complaint indicates that
the damages to the class could include over $150 million paid by the
Company to terminate the contracts with the Canadian gas producers in
November 1993. The complaint also seeks recovery of three times the
amount of the actual damages pursuant to antitrust laws.
The Company believes the case is without merit and has filed a motion
to dismiss the complaint. The Company believes that the ultimate
outcome will not have a significant adverse impact on its financial
position.
Hinkley Litigation: In 1993, a complaint was filed 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 the Company'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.
In 1987, the Company undertook an extensive project to remediate
potential groundwater chromium contamination. The Company has
incurred substantially all of the costs it currently deems necessary
to clean up the affected groundwater contamination. In accordance
with the remediation plan approved by the regional water quality
control board, the Company will continue to monitor the affected area
and perform environmental assessments.
In November 1993, the parties engaged in private mediation sessions.
Since then, plaintiffs' counsel has offered to compromise and
settle plaintiffs' claims against the Company for $265 million.
However, that amount related to the claims of only approximately two-
thirds of the presently known plaintiffs. There have been subsequent
mediation sessions but no resolution has been reached and discussions
continue.
The Company is unable to estimate the ultimate outcome of this
matter, but such outcome could have a significant adverse impact on
the Company's results of operations. The Company believes that the
ultimate outcome of this matter will not have a significant adverse
impact on its financial position. (See Note 4 of Notes to
Consolidated Financial statements for further discussion.)
County Franchise Fees Litigation: In March 1994, Santa Clara and
Alameda counties filed a class action suit against the Company on
behalf of themselves and 45 other counties in the Company's service
area. This lawsuit alleges that the Company underpaid franchise fees
to the counties for the right to use or occupy public streets or
roads as a result of incorrectly computing these payments. Should
plaintiffs prevail, the Company currently estimates that its annual
system-wide county franchise fees could increase by approximately $15
million. In addition, the amount of damages for alleged
underpayments for the years 1987 through 1993 could be as high as
$127 million, including interest, as of June 30, 1994. The Company
believes that the ultimate outcome will not have a significant
adverse impact on its financial position or results of operations.
City Franchise Fees Litigation: In May 1994, the City of Santa Cruz
filed a class action suit against the Company on behalf of itself and
106 other cities in the Company's service area. The complaint
alleges that the Company has improperly underpaid electric franchise
fees to the cities by calculating fees at different rates from other
cities. Should plaintiffs prevail, the Company currently estimates
that its annual system-wide city franchise fees could increase by
approximately $17 million. In addition, the amount of damages for
alleged underpayments for the years 1987 through 1993 could be as
high as $117 million, including interest, as of June 30, 1994. The
Company believes that the ultimate outcome will not have a
significant adverse impact on its financial position or results of
operations.
LIQUIDITY AND CAPITAL RESOURCES
- -------------------------------
Sources of Capital:
- ------------------
The following debt and equity securities were issued, reacquired or
redeemed from January 1 through June 30, 1994:
(in thousands)
Debt:
Issued Interest Rates Amount
- ------ -------------- -------------
Medium-term notes 6.50% to 7.88% $30,000
Redeemed
- --------
Mortgage bonds 7.50% 79,900
Medium-term notes 10.05% and 10.10% 40,000
Eurobonds 12.00% 15,334
Equity:
Issued Dividend Rates Amount
- ------ -------------- --------------
Preferred stock 6.30% $62,500
Common stock
Savings Fund Plan N/A 91,322
Dividend Reinvestment
Plan N/A 46,649
Long-term Incentive
Plan N/A 797
Redeemed/Reacquired
- -------------------
Preferred stock 8.16% 75,000
Common stock N/A 60,320
Proceeds from the issuance of securities were used for capital
expenditures, refundings and other general corporate purposes.
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.
Although the ultimate amount of costs that will be incurred by the
Company in connection with its compliance and remediation activities
is difficult to estimate due to uncertainty concerning the Company's
responsibility and the extent of contamination, the complexity of
environmental laws and regulations and the selection of compliance
alternatives, the Company has an accrued liability as of June 30,
1994, of $62 million for hazardous waste remediation costs. (See
further discussion of the accrued liability for hazardous waste
remediation costs in Note 4 of Notes to Consolidated Financial
Statements.)
Sales and Acquisition:
- ---------------------
Sales: In April 1994, the Company announced that it has deferred its
plan to divest PG&E Resources Company (Resources), a wholly owned
indirect subsidiary of Enterprises. Resources, which is engaged in
oil and gas exploration, is headquartered in Dallas, Texas. In June
1994, Resources entered into multiple contracts to sell several of
its oil and gas properties. The Company recorded a $19 million
pretax loss during the second quarter for those properties to be sold
which have a carrying value in excess of their market value. Gains
to be realized in the third quarter from the sale of the remaining
properties held for sale are expected to offset these losses. The
Company anticipates that all sales will be completed in the third
quarter of 1994.
Acquisition: In July 1994, the Company announced that Enterprises
and Bechtel Enterprises have concluded an agreement for the purchase
of 100 percent of J. Makowski Co., Inc., a national company engaged
in the development of natural gas-fueled power generation projects
and natural gas distribution, supply and underground storage
projects. Enterprises expects to have a majority interest in the
Company. The total purchase price is approximately $250 to $300
million and the transaction is expected to be completed during the
third quarter of 1994.
PART II. OTHER INFORMATION
---------------------------
Item 1. Legal Proceedings
-----------------
A. QF Transmission Constrained Area Litigation
On July 20, 1994, the Company settled the lawsuit brought against
it by Pacific Oroville Power, Inc. (POPI). The lawsuit was
previously disclosed in the Company's Form 10-K for the fiscal
year ended December 31, 1993. The settlement was reached
following an eight-month jury trial, at the conclusion of which
the jury indicated they were deadlocked and unable to reach a
verdict. The settlement did not have a significant adverse
impact on the Company's financial position or results of
operations.
B. Time-Of-Use Meter Litigation
On July 21, 1994, Milton L. Grinstead, Michael Davis, Joan A.
Williamson, Frank H. Lacy, and Matthew Doerksen filed a complaint
in the Stanislaus County Superior Court against the Company on
behalf of themselves and purportedly as a class action on behalf
of all of the Company's customers, for "refund of unlawfully
charged fees."
The complaint alleges that the Company improperly failed to
notify its customers of the most favorable rates available to
each particular customer. The complaint focuses on the "time-of-
use" billing option, which allows customers to save money by
shifting their electricity use to off-peak hours when electricity
is cheaper. Plaintiffs contend that all customers could have
saved an average of $50-$75 per month per customer had they been
placed on time-of-use rates. The complaint seeks damages
estimated to be in excess of $16 billion.
The Company believes that the ultimate outcome of this matter
will not have a significant adverse impact on its financial
position or results of operations.
Item 5. Other Information
-----------------
Ratios of Earnings to Fixed Charges and Ratios of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
The Company's earnings to fixed charges ratio for the six months
ended June 30, 1994 was 3.48. The Company's earnings to combined
fixed charges and preferred stock dividends ratio for the six
months ended June 30, 1994 was 3.04. 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 3.1 Restated Articles of Incorporation of
the Company effective as of July 26,
1994
Exhibit 10 Contract Between Pacific Gas and
Electric Co. and Jerry R. McLeod
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
(b) Reports on Form 8-K during the second quarter of 1994 and
through the date hereof:
1. April 2l, 1994
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date
Financial Results
B. California Public Utilities Commission Proceedings
- Electric Fuel and Sales Balancing Accounts -
ECAC/ERAM
- Biennial Cost Allocation Proceeding (BCAP)
- Electric Industry Restructuring
C. Franchise Fees Litigation
2. June 7, 1994
Item 5. Other Events
A. California Public Utilities Commission Proceedings
- Electric Industry Restructuring
B. Restructuring of Canadian Gas Supply Arrangmenets
C. Cities Franchise Fees Litigation
D. Management Changes
3. July 6, 1994
Item 5. Other Events
A. Restructuring of Gas Supply Arrangements -
Recovery of Interstate Transportation Demand
Charges
B. Diablo Canyon Nuclear Power Plant - Nuclear Fuel
Supply and Disposal
C. Acquisition by PG&E Enterprises/Bechtel Enterprise
4. July 25, 1994
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date
Financial Results
B. California Public Utilities Commission Proceedings
- Electric Fuel and Sales Balancing Accounts -
ECAC/ERAM
C. Diablo Canyon Nuclear Power Plant - Diablo Canyon
Rate Case Settlement
5. August 3, 1994
Item 5. Other Events
A. California Public Utilities Commission Proceedings
- 1995 Electric Rate Stablization
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
PACIFIC GAS AND ELECTRIC COMPANY
GORDON R. SMITH
August 12, 1994 By______________________________
GORDON R. SMITH
Vice President and
Chief Financial Officer
EXHIBIT INDEX
Exhibit
Number Exhibit
- ------- ---------------------------------
3.1 Restated Articles of Incorporation of the
Company effective as of July 26, 1994
10 Contract Between Pacific Gas and Electric
Company and Jerry R. McLeod
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