FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
---------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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
-------------------------------------------
(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 October 31, 1994
--------------- -------------------------------
Common Stock, $5 par value 432,273,143 shares
Form 10-Q
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TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION Page
- ------------------------------ ----
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
1994 Workforce Reduction..................... 6
Note 2: Competition and Regulation..................... 6
Electric Industry Restructuring.............. 6
Energy Cost Adjustment Clause................ 8
Note 3: Reasonableness Proceedings..................... 9
Note 4: Contingencies
Helms Pumped Storage Plant................... 10
Nuclear Insurance............................ 10
Environmental Remediation.................... 11
Legal Matters................................ 12
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.................................... 16
Operating Expenses.................................... 16
Diablo Canyon......................................... 16
1994 Workforce Reduction.............................. 17
Proposed Accounting Standard.......................... 17
Changing Competitive and Regulatory Environment....... 18
Rate Matters.......................................... 21
Reasonableness Proceedings............................ 25
Legal Matters......................................... 26
Liquidity and Capital Resources
Sources of Capital.................................... 26
Environmental Remediation............................. 27
Sales and Acquisition ................................ 27
PART II. OTHER INFORMATION
- ----------------------------
Item 1. Legal Proceedings
Antitrust Litigation.................................. 28
Hinkley Litigation.................................... 29
Time-of-Use Meter Litigation.......................... 29
Potter Valley Hydroelectric Project................... 30
Item 5. Ratios of Earnings to Fixed Charges and Ratios of
Earnings to Combined Fixed Charges and Preferred
Stock Dividends....................................... 30
Item 6. Exhibits and Reports on Form 8-K........................ 30
SIGNATURE.......................................................... 33
PART I. FINANCIAL INFORMATION
------------------------------
Item 1. Consolidated Financial Statements
---------------------------------
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
Three months ended September 30, Nine months ended September 30,
(in thousands, ------------------------------- ------------------------------
except per share amounts) 1994 1993 1994 1993
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric $2,356,034 $2,344,149 $6,076,242 $5,896,493
Gas 499,187 603,145 1,732,930 1,978,744
---------- ---------- ---------- ----------
Total operating revenues 2,855,221 2,947,294 7,809,172 7,875,237
---------- ---------- ---------- ----------
OPERATING EXPENSES
Cost of electric energy 817,955 782,482 2,013,543 1,692,731
Cost of gas 74,514 167,876 409,278 651,960
Distribution 41,290 49,965 154,270 159,188
Transmission 63,025 73,588 200,071 253,274
Customer accounts and services 95,532 95,794 282,086 278,245
Maintenance 93,942 96,227 323,096 333,181
Depreciation and decommissioning 347,867 327,980 1,041,610 967,976
Administrative and general 234,291 253,133 697,279 750,973
Workforce reduction costs - 55,500 - 196,700
Income taxes 347,939 365,584 808,532 754,884
Property and other taxes 71,267 72,971 227,506 230,676
Other 82,905 80,212 256,828 271,432
---------- ---------- ---------- ----------
Total operating expenses 2,270,527 2,421,312 6,414,099 6,541,220
---------- ---------- ---------- ----------
OPERATING INCOME 584,694 525,982 1,395,073 1,334,017
---------- ---------- ---------- ----------
OTHER INCOME AND (INCOME
DEDUCTIONS)
Interest income 20,608 21,897 57,178 64,064
Allowance for equity funds
used during construction 5,042 11,584 14,779 33,045
Other--net (1,463) (7,232) (5,229) 940
---------- ---------- ---------- ----------
Total other income and
(income deductions) 24,187 26,249 66,728 98,049
---------- ---------- ---------- ----------
INCOME BEFORE INTEREST EXPENSE 608,881 552,231 1,461,801 1,432,066
---------- ---------- ---------- ----------
INTEREST EXPENSE
Interest on long-term debt 164,156 177,849 487,348 528,583
Other interest charges 22,726 26,643 81,911 76,989
Allowance for borrowed funds
used during construction (3,634) (8,360) (11,408) (30,619)
---------- ---------- ---------- ----------
Net interest expense 183,248 196,132 557,851 574,953
---------- ---------- ---------- ----------
NET INCOME 425,633 356,099 903,950 857,113
Preferred dividend requirement 14,494 15,520 43,314 48,913
---------- ---------- ---------- ----------
EARNINGS AVAILABLE FOR
COMMON STOCK $ 411,139 $ 340,579 $ 860,636 $ 808,200
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING 430,439 432,472 429,584 430,527
EARNINGS PER COMMON SHARE $.96 $.79 $2.00 $1.88
DIVIDENDS DECLARED PER COMMON SHARE $.49 $.47 $1.47 $1.41
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
September 30, December 31,
(in thousands) 1994 1993
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<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $ 17,089,878 $ 16,633,772
Diablo Canyon 6,598,496 6,518,413
Gas 7,391,798 7,146,741
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Total plant in service (at original cost) 31,080,172 30,298,926
Accumulated depreciation and decommissioning (12,160,827) (11,235,519)
------------ ------------
Net plant in service 18,919,345 19,063,407
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CONSTRUCTION WORK IN PROGRESS 487,175 620,187
OTHER NONCURRENT ASSETS
Oil and gas properties 414,239 573,523
Nuclear decommissioning funds 609,901 536,544
Other assets 1,029,360 497,689
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Total other noncurrent assets 2,053,500 1,607,756
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CURRENT ASSETS
Cash and cash equivalents 141,514 61,066
Accounts receivable
Customers 1,305,654 1,264,907
Other 101,603 123,255
Allowance for uncollectible accounts (24,592) (23,647)
Regulatory balancing accounts receivable 1,408,468 992,477
Inventories
Materials and supplies 224,808 239,856
Gas stored underground 163,229 170,345
Fuel oil 94,275 109,615
Nuclear fuel 141,117 134,411
Prepayments 33,200 56,062
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Total current assets 3,589,276 3,128,347
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DEFERRED CHARGES
Income tax-related deferred charges 1,151,387 1,246,890
Diablo Canyon costs 405,665 419,775
Unamortized loss net of gain on reacquired debt 387,136 395,659
Workers' compensation and disability claims recoverable 282,382 192,203
Other 647,597 488,302
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Total deferred charges 2,874,167 2,742,829
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TOTAL ASSETS $ 27,923,463 $ 27,162,526
============ ============
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<FN>
(continued on next page)
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
September 30, December 31,
(in thousands) 1994 1993
- --------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,149,573 $ 2,136,095
Additional paid-in capital 3,778,642 3,666,455
Reinvested earnings 2,807,204 2,643,487
----------- -----------
Total common stock equity 8,735,419 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 8,985,131 9,292,100
----------- -----------
Total capitalization 18,591,045 18,621,132
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OTHER NONCURRENT LIABILITIES
Customer advances for construction 152,408 152,872
Workers' compensation and disability claims 249,000 157,000
Other 579,838 246,950
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Total other noncurrent liabilities 981,246 556,822
----------- -----------
CURRENT LIABILITIES
Short-term borrowings 346,305 764,163
Long-term debt 257,725 221,416
Accounts payable
Trade creditors 436,966 472,985
Other 409,034 389,065
Accrued taxes 582,835 303,575
Deferred income taxes 469,249 315,584
Interest payable 168,141 82,105
Dividends payable 227,074 203,923
Other 360,744 487,809
----------- -----------
Total current liabilities 3,258,073 3,240,625
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DEFERRED CREDITS
Deferred income taxes 4,030,250 3,978,950
Deferred investment tax credits 396,292 410,969
Other 666,557 354,028
----------- -----------
Total deferred credits 5,093,099 4,743,947
CONTINGENCIES (Notes 2, 3 and 4) - -
----------- -----------
TOTAL CAPITALIZATION AND LIABILITIES $27,923,463 $27,162,526
=========== ===========
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
Nine months ended September 30,
------------------------------
(in thousands) 1994 1993
- --------------------------------------------------------------------------------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 903,950 $ 857,113
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and decommissioning 1,041,610 967,976
Amortization 49,156 62,066
Deferred income taxes and investment tax credits--net 275,459 278,603
Allowance for equity funds used during construction (14,779) (33,045)
Net effect of changes in operating assets
and liabilities
Accounts receivable (18,150) 37,319
Regulatory balancing accounts receivable (415,991) (154,550)
Inventories 30,798 (5,360)
Accounts payable (16,050) 43,571
Accrued taxes 292,820 65,494
Other working capital (17,688) 509,612
Other deferred charges 35,274 (188,126)
Other noncurrent liabilities 206,183 (17,603)
Other deferred credits 102,590 43,637
Other--net (1,196) 19,383
---------- ----------
Net cash provided by operating activities 2,453,986 2,486,090
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures (686,486) (1,353,488)
Allowance for borrowed funds used during construction (11,408) (30,619)
Nonregulated expenditures (491,926) (133,235)
Other--net 16,625 32,746
---------- ----------
Net cash used by investing activities (1,173,195) (1,484,596)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 208,654 202,466
Common stock repurchased (121,277) (4,974)
Preferred stock issued 62,312 200,000
Preferred stock redeemed (83,020) (302,608)
Long-term debt issued 55,000 3,189,584
Long-term debt matured or reacquired (321,620) (2,523,818)
Short-term debt redeemed--net (417,858) (679,341)
Dividends paid (666,453) (639,345)
Other--net 83,919 (38,388)
---------- ----------
Net cash used by financing activities (1,200,343) (596,424)
---------- ----------
NET CHANGE IN CASH AND CASH EQUIVALENTS 80,448 405,070
CASH AND CASH EQUIVALENTS AT JANUARY 1 61,066 97,592
---------- ----------
CASH AND CASH EQUIVALENTS AT SEPTEMBER 30 $ 141,514 $ 502,662
========== ==========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 420,834 $ 404,409
Income taxes 403,219 433,939
- --------------------------------------------------------------------------------------------
<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
- ----------------
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 Nuclear Power
Plant (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. 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.
As of September 30, 1994, the Company had accumulated in external
trust funds $610 million (at fair value) to be used for the
decommissioning of its nuclear facilities.
1994 Workforce Reduction:
- ------------------------
In August 1994, the Company announced a workforce reduction. The gross
annual labor savings from this reduction are projected to be between
$150 million and $185 million.
The majority of the proposed job reductions are expected to occur by
the first quarter of 1995 through a voluntary retirement incentive
(VRI) program. Assuming that a similar percentage of eligible
employees accept the VRI as accepted a similar offer in 1993 and that a
total of 3,000 positions are eliminated, it is estimated that the VRI
and severance programs will cost approximately $280 million. In
addition, depending on the impact of the reductions on the Company's
pension and other postretirement benefit plans, the Company may have to
recognize an additional cost of up to approximately $50 million. The
ultimate cost will vary depending on the actual mix of benefits taken
and number of positions eliminated.
Substantially all of the cost of the workforce reduction will be
expensed in the fourth quarter of 1994, when the VRI acceptance period
ends and the specifics of the severance program are known. The Company
does not plan to seek rate recovery for the cost of the workforce
reduction as it did with the 1993 program.
NOTE 2: COMPETITION AND REGULATION
- -----------------------------------
Competitive and regulatory changes in the Company's gas and electric
businesses are occurring at an ever-increasing rate. These changes
will impact the way the Company conducts its business and may affect
recovery of certain assets.
Electric Industry Restructuring:
- -------------------------------
In April 1994, the California Public Utilities Commission (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 ratemaking 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. Utilities 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 investment in Diablo
Canyon. In connection with its proposal, the Company indicated that it
would consider increasing Diablo Canyon's depreciation expense to
reflect a decrease in the plant's economic useful life.
Other California utilities and interested parties have also filed
comments on the CPUC proposal and have made proposals of their own.
The CPUC is expected to adopt a policy statement by the end of the
first quarter of 1995. However, this policy statement will be subject
to hearings and 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 $3.8 billion of regulatory
assets, including balancing accounts, as of September 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, the impact could cause the Company to
write off applicable portions of its 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 or the Company determines that future
electric generation rates will no longer be based on cost-of-service,
the Company will discontinue application of SFAS No. 71 for the
electric generation portion of the Company's operations. The Company
is evaluating the current regulatory and competitive environment to
determine whether and when such a discontinuance would be appropriate.
If such discontinuance should occur, the Company would write off all
applicable generation-related regulatory assets to the extent that
transition cost recovery is not assured. The regulatory assets
attributable to electric generation, excluding balancing accounts, are
estimated to be $1.4 billion at September 30, 1994. This amount is
based on the Company's current allocation of these assets to the
electric generation portion of the Company's operations; the actual
amount could vary depending on the allocation methods ultimately used.
The CPUC's OIR/OII could also impact the Company's recovery of its
costs and investments in other electric utility assets and the Diablo
Canyon rate case settlement. (See the Rate Matters section of
Management's Discussion and Analysis for further discussion.)
The final determination of the financial impact will depend on the form
of regulation, including transition mechanisms, if any, ultimately
adopted by the CPUC. Currently, the Company is unable to predict the
ultimate outcome of the electric industry restructuring or predict
whether such outcome will have significant impact 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.
Energy Cost Adjustment Clause (ECAC):
- ------------------------------------
In accordance with mechanisms established by the CPUC, the Company
accumulates the differences between actual costs of generating
electricity and the revenues designed to recover such costs. To the
extent costs exceed revenues, the undercollection accumulates in the
ECAC balancing account. Over the past few years, the Company has
experienced a significant increase in the level of balancing account
undercollection related to its electric energy costs. The increase
primarily results from Diablo Canyon's generation exceeding that
forecasted in the annual ECAC proceeding, increased fuel costs, the use
of higher-cost energy sources to compensate for less than normal hydro
conditions and the deferred recovery of undercollected balances. As of
September 30, 1994, the ECAC balancing account undercollection was
approximately $730 million.
Absent significant electric rate increases, recovery of the ECAC
undercollection would be dependent upon achieving extensive cost
reductions. In 1993 and 1994, the Company elected to defer, without
interest, recovery of the undercollection until such time as it could
implement sufficient cost reductions to facilitate recovery without
significantly increasing rates.
The ability of the Company to recover the ECAC balancing account
undercollection has been limited as a result of the Company's freeze on
retail electric rates. The Company kept retail electric rates flat in
1994, and proposes to freeze such rates in 1995, and has a five-year
goal of reducing its system-wide average electric rates. The Company
is pursuing various options to recover the ECAC undercollection in a
reasonable period of time. In the event that none of these options
result in the recovery of the ECAC undercollection, the Company will
have to write off some or all of the ECAC undercollection.
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.
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 up to 700
million cubic feet per day of gas (approximately 70 percent of 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.
A number of other reasonableness issues related to the Company's gas
procurement practices and supply operations for periods dating from
1988 to May 1994 are still under review by the CPUC. The DRA had
recommended disallowances of $142 million and a penalty of $50 million
and indicated that it was considering additional recommendations for
these issues. The Company and the DRA have signed settlement
agreements to resolve for $68 million substantially all of these
recommended and potential disallowances, as well as the recommended
penalty.
Significant issues covered by the agreements include (1) the Company's
purchases of Canadian, Southwest and California gas from 1991 through
May 1994; (2) the investigation by the DRA of Alberta and Southern Gas
Co. Ltd (A&S), the Company's wholly owned gas purchasing subsidiary,
and Alberta Natural Gas Company Ltd, a former affiliate of the Company,
for the period 1988 through May 1994; (3) the effects of Canadian gas
prices on amounts paid by the Company for Northwest power purchases for
1988 through 1992 and power from qualifying facilities and geothermal
steam services for 1991 and 1992; (4) the Company's gas storage
operations for 1991 and 1992; (5) the Company's Southwest gas purchases
for 1988 through 1990; and (6) Canadian gas restructuring transition
costs billed to PG&E.
Agreements with the DRA do not constitute a CPUC decision and are
subject to modification by the CPUC in its final decisions.
Financial Impact of Reasonableness Proceedings: To date, the Company
has accrued $171 million ($61 million in the fourth quarter of 1993 and
approximately $90 and $20 million in the first and third quarters of
1994, respectively) for gas reasonableness matters discussed above. If
the agreements between the Company and the DRA are adopted by the CPUC
without modification, there will be no further financial impact
relating to issues covered by the agreements. The Company believes
that the ultimate resolution of any remaining reasonableness matters
will not have a significant adverse impact on the Company's financial
position or results of operations.
The Company intends to contest the CPUC's decision on the Canadian gas
disallowance for 1988 through 1990, the cost of which has been fully
accrued as part of the $171 million discussed above.
NOTE 4: CONTINGENCIES
- ----------------------
Helms Pumped Storage Plant (Helms):
- ----------------------------------
The Company has signed a settlement with the DRA regarding the recovery
of Helms costs not currently in rate base and prior-year revenue
requirements related to these costs. The settlement provides for
recovery of substantially all of the remaining net unrecovered costs
(after adjustment for depreciation) and revenues, which totaled $104
million at September 30, 1994.
The settlement has been submitted to the CPUC for approval with a
decision anticipated during the fourth quarter of 1994. If the
settlement is adopted by the CPUC, it will not have a significant
impact on the Company's financial position or results of operations.
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 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 and 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 September 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 or necessary remediation
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 August 1994, the federal district court in
Fresno, California, granted the Company's motion to dismiss the
federal and state antitrust claims and the state unfair practices
claims against the Company and Pacific Gas Transmission Company
(PGT), a wholly owned subsidiary of the Company, by the County of
Stanislaus, California, and a residential customer of the Company.
The court also granted the plaintiffs' motion seeking class
certification. The lawsuit was filed on behalf of the plaintiffs and
purportedly as a class action on behalf of all natural gas customers
of the Company during the period of February 1988 through October
1993, and alleged that the purchase of natural gas in Canada by A&S
was accomplished in violation of various antitrust laws resulting in
increased prices of natural gas for PG&E's customers. Damages to the
class members was estimated as potentially exceeding $800 million.
The complaint indicated 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.
In September 1994, the plaintiffs filed an amended complaint in which
A&S has been added as a defendant. The amended complaint restates
the claims in the original complaint and alleges that the defendants,
through anticompetitive practices, precluded certain customers of the
Company access to alternative sources of gas in Canada over the PGT
pipeline. A new motion to dismiss was filed by the Company in early
November 1994. The Company believes that the ultimate outcome of this
matter 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.
The Company has reached an agreement with plaintiffs' counsel and over
90 percent of the identified 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, the Company will pay
an aggregate amount of no more than $400 million in settlement of such
plaintiffs' claims, including $50 million paid to escrow to date. In
turn, those plaintiffs, and their attorneys, agree to indemnify the
Company against any additional losses the Company 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 September 30, 1994, the Company has a remaining reserve of $50
million against any future potential liability in this case.
Although the Company is not able to estimate the amount of loss it
will ultimately incur in connection with this matter, the ultimate
outcome of this matter 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.
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 $129 million,
including interest, as of September 30, 1994. 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.
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 underpaid electric franchise fees to the
cities by improperly 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
$119 million, including interest, as of September 30, 1994. 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 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 three and nine months ended September 30,
1994 and 1993, selected financial information for the three types of
operations is shown below:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Utility Diablo Canyon Enterprises Total
(in millions, except -------------- ------------- ------------ --------------
per share amounts) 1994 1993 1994 1993 1994 1993 1994 1993
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
THREE MONTHS ENDED
SEPTEMBER 30
Operating revenues
Electric $ 1,759 $ 1,763 $ 597 $ 581 $ - $ - $ 2,356 $ 2,344
Gas 446 540 - - 53 63 499 603
------- ------- ------ ------ ----- ----- ------- -------
Total operating revenues 2,205 2,303 597 581 53 63 2,855 2,947
Operating expenses 1,861 1,993 357 371 52 57 2,270 2,421
------- ------- ------ ------ ----- ----- ------- -------
Operating income $ 344 $ 310 $ 240 $ 210 $ 1 $ 6 $ 585 $ 526
======= ======= ====== ====== ===== ===== ======= =======
Net income $ 206 $ 197 $ 203 $ 154 $ 17 $ 5 $ 426 $ 356
Earnings per common share $ .46 $ .43 $ .46 $ .35 $ .04 $ .01 $ .96 $ .79
NINE MONTHS ENDED
SEPTEMBER 30
Operating revenues
Electric $ 4,646 $ 4,478 $1,430 $1,418 $ - $ - $ 6,076 $ 5,896
Gas 1,573 1,794 - - 160 185 1,733 1,979
------- ------- ------ ------ ----- ----- ------- -------
Total operating revenues 6,219 6,272 1,430 1,418 160 185 7,809 7,875
Operating expenses 5,311 5,440 939 925 164 176 6,414 6,541
------- ------- ------ ------ ----- ----- ------- -------
Operating income (loss) $ 908 $ 832 $ 491 $ 493 $ (4) $ 9 $ 1,395 $ 1,334
======= ======= ====== ====== ===== ===== ======= =======
Net income $ 521 $ 496 $ 379 $ 339 $ 4 $ 22 $ 904 $ 857
Earnings per common share $ 1.14 $ 1.07 $ .85 $ .76 $ .01 $ .05 $ 2.00 $ 1.88
Total assets at September 30 $20,329 $20,139 $6,091 $6,287 $1,503 $1,019 $27,923 $27,445
- ----------------------------------------------------------------------------------------------------
</TABLE>
Earnings Per Common Share:
- -------------------------
The Company's earnings per common share for the three months ended
September 30, 1994, were higher than for the comparable period of 1993,
reflecting an increase in Diablo Canyon earnings per share primarily
due to the annual increase in the price per kilowatthour (kWh) as
provided in the Diablo Canyon rate case settlement, partially offset by
a greater number of scheduled refueling days in the current quarter.
The results for the third quarter of 1993 reflected one-time charges
related to the Company's 1993 workforce reduction program,
restructuring of Canadian natural gas contracts and an increase in the
federal income tax rate.
The Company's earnings per common share for the nine months ended
September 30, 1994, were higher than for the comparable period of 1993
reflecting lower costs resulting from the Company's 1993 workforce
reduction program and an increase in Diablo Canyon earnings per share.
The increase in Diablo Canyon earnings per share was primarily due to
the annual increase in the price per kWh as provided in the Diablo
Canyon rate case settlement, offset by a greater number of unscheduled
outage and refueling days in 1994, compared to the same period of 1993.
These favorable variances were partially offset by higher expenses in
1994 related to gas matters and an increase in litigation reserves.
The results for 1993 reflected one-time charges related to the
Company's 1993 workforce reduction program, restructuring of Canadian
natural gas contracts and an increase in the federal income tax rate.
Since the Diablo Canyon rate case settlement in 1988, Diablo Canyon has
made an increasing contribution to the Company's total earnings per
share. For the year ended December 31, 1993, Diablo Canyon contributed
$1.11 to the total earnings per share of $2.33 (48 percent). In the
nine-month period ended September 30, 1994, Diablo Canyon earned $.85
per share or 43 percent of the total earnings per share of $2.00.
As discussed below, the Division of Ratepayer Advocates (DRA), a
consumer advocacy branch of the California Public Utilities Commission
(CPUC) staff, has filed a petition which seeks to modify the Diablo
Canyon pricing methodology and freeze the current price for Diablo
Canyon. An Administrative Law Judge (ALJ) of the CPUC has set a
hearing on the matter in December, 1994. In addition, the Company has
a five-year goal of reducing its system-wide average electric rates and
also, as discussed below, there are a number of proposals to
restructure the electric industry. These factors and increasing
competition will impact the Company's ability to charge rates which
will permit full recovery of Diablo Canyon revenues as provided in the
settlement.
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 restructuring of the electric industry 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 months ended September 30, 1994,
increased compared with the same period of 1993, mostly due to
increased revenues from Diablo Canyon resulting primarily from the
annual increase in the price per kWh as provided in the Diablo Canyon
rate case settlement. Electric revenue for the nine months ended
September 30, 1994, increased compared with the same period of 1993,
substantially all due to an increase in revenues related to higher
electric energy costs in 1994.
Gas revenues for the three and nine months ended September 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 allowed
many of the Company's noncore customers to arrange for the purchase of
their own gas supplies, with the Company providing only transportation
service for these noncore customers.
Operating Expenses:
- ------------------
The decreases in operating expenses for the three and nine months ended
September 30, 1994, compared with the same periods of 1993, were due to
expenses incurred in 1993 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.
Additionally, income taxes were lower for the three months ended
September 30, 1994, as a result of the comparable 1993 period
reflecting a one-time adjustment to income taxes due to the increase in
the federal income tax rate. These decreases were 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 kWh of purchased power, a
rate refund made by the Company for purchased power and an increase in
the volume of gas used to provide electric energy. Additionally, the
increase in electric energy costs for the nine months ended September
30, 1994, is partially due to a credit for purchased power received by
the Company during the comparable period of 1993.
Diablo Canyon:
- -------------
The Diablo Canyon plant capacity factors for the nine months ended
September 30, 1994 and 1993, were 83 percent and 87 percent,
respectively, reflecting the scheduled refueling outages for both units
in 1994 and for Unit 2 in 1993. The 1994 scheduled refueling outage
for Unit 2 began on September 24, 1994 and was completed on
October 28, 1994. The 1994 capacity factors were also impacted by
approximately 24 days of extended unscheduled outages during the nine
months ended September 30, 1994, due to two minor nonnuclear problems.
There were no extended unscheduled outages during the nine months ended
September 30, 1993. Through September 30, 1994, the lifetime capacity
factor for the plant was 80 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. (See the
Earnings Per Common Share section for further discussion of Diablo
Canyon's contributions to earnings.)
1994 Workforce Reduction:
- ------------------------
In August 1994, the Company announced a workforce reduction. The gross
annual labor savings from this reduction are projected to be between
$150 million and $185 million.
The majority of the proposed job reductions are expected to occur by
the first quarter of 1995 through a voluntary retirement incentive
(VRI) program. Assuming that a similar percentage of eligible
employees accept the VRI as accepted a similar offer in 1993 and that a
total of 3,000 positions are eliminated, it is estimated that the VRI
and severance programs will cost approximately $280 million. In
addition, depending on the impact of the reductions on the Company's
pension and other postretirement benefit plans, the Company may have to
recognize an additional cost of up to approximately $50 million. The
ultimate cost will vary depending on the actual mix of benefits taken
and number of positions eliminated.
Substantially all of the cost of the workforce reduction will be
expensed in the fourth quarter of 1994, when the VRI acceptance period
ends and the specifics of the severance program are known. The Company
does not plan to seek rate recovery for the cost of the workforce
reduction as it did with the 1993 program.
Proposed Accounting Standard:
- ----------------------------
The Financial Accounting Standards Board (FASB) has proposed a new
accounting standard, "Accounting for the Impairment of Long-Lived
Assets," which is scheduled to be issued by the end of 1994. The
Company would be required to adopt the new standard beginning January
1, 1995, but may elect to adopt earlier.
If issued by the FASB as proposed, the new standard would require,
among other things, that regulatory assets recorded as a result of
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting
for the Effects of Certain Types of Regulation," continue to be
probable of recovery in rates at all times, rather than only at the
time the regulatory asset was recorded. The financial impact of the
adoption of the new standard is discussed below in Changing Competitive
and Regulatory Environment.
In addition, the new standard as proposed will require the Company to
evaluate impairment of its investment in proved oil and gas properties
and related equipment and facilities using the same groupings of those
costs as is used to amortize them. The impact of adopting the standard
on the Company's oil and gas operations is discussed in the Sales and
Acquisition section.
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 lower prices. In April 1994, the 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 direct access
over a six-year period beginning in 1996. The Company has filed a
response to the CPUC proposal and 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 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. Utilities 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.
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 charge would be
allocated to and collected from customers. The Diablo Canyon rate case
settlement was not specifically addressed in the OIR/OII.
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 investment in Diablo
Canyon. In connection with its proposal, the Company indicated that it
would consider increasing Diablo Canyon's depreciation expense to
reflect a decrease in the plant's economic useful life.
The other California utilities and other interested parties are also
filing responses to the OIR/OII. The CPUC is expected to adopt a
policy statement by the end of the first quarter of 1995. However,
this policy statement will be subject to hearings and state legislative
review before it can be implemented by the CPUC.
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. 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 details of the
CPUC's electric industry restructuring plan are definitive enough to
allow it, the Company proposes to revise its RRI filing to reflect
direct access, which could 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. 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 (GRCs), 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 Energy Cost Adjustment Clause (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 of certain performance standards. 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. The Company has proposed
that PBR base revenue indexing begin in 1997.
Specific proposals regarding a gas procurement mechanism were not
included in the Company's March 1994 filing. However, the Company and
the DRA have agreed on a gas procurement incentive mechanism for core
procurement purchases as a substitute for reasonableness reviews for
certain costs incurred after June 1, 1994. In general, this mechanism
would measure the Company's gas procurement costs against market
benchmarks and would provide for the sharing of costs or cost savings
between ratepayers and shareholders should those costs be above or
below a range determined to be reasonable. The Company expects to file
an application with the CPUC seeking approval of this mechanism in the
fourth quarter of 1994.
Long-Term Noncore Gas Transportation Prices: In June 1994, the Company
filed a petition with the CPUC requesting authorization to implement
the optional long-term competitive noncore gas transportation prices
which would be offered to the Company's largest gas transport customers
under a ten-year service agreement. In September, the CPUC approved
the petition subject to certain restrictive conditions that were not
part of the Company's original proposal. In October, the Company filed
an application for rehearing challenging the constitutionality of those
conditions and indicated that it intends to decline to implement the
proposed prices if the CPUC continues to insist on its proposed
conditions as a basis of approval. If the Company cannot obtain CPUC
approval on its original proposal, it is unlikely that it will proceed
to offer these long-term noncore gas transportation prices.
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 SFAS No. 71. As a result of
applying the provisions of SFAS No. 71, the Company has accumulated
approximately $3.8 billion of regulatory assets, including balancing
accounts, as of September 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, the impact could cause the Company to
write off applicable portions of its 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 as proposed or the Company determines that
future electric generation rates will no longer be based on cost-of-
service, the Company will discontinue application of SFAS No. 71 for
the electric generation portion of the Company's operations. The
Company is evaluating the current regulatory and competitive
environment to determine whether and when such a discontinuation would
be appropriate. If such discontinuance should occur, the Company
would write off all applicable generation-related regulatory assets to
the extent that transition cost recovery is not assured. The
regulatory assets attributable to electric generation, excluding
balancing accounts, were estimated to be $1.4 billion at September 30,
1994. This amount is based on the Company's current allocation of
these assets to the electric generation portion of the Company's
operations; the actual amount could vary depending on the allocation
methods ultimately used. The CPUC's OIR/OII could also impact the
Company's recovery of its costs and investments in other electric
utility assets and the Diablo Canyon rate case settlement.
As discussed above in the Proposed Accounting Standard section, the
FASB may adopt a new accounting standard related to the impairment of
long-lived assets. If adopted as proposed, some or all of the
regulatory assets discussed above may not meet the new probable of
recovery standard due to the uncertain recovery period raised by the
transition to direct access proposed by the OIR/OII.
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.
The final determination of the financial impact will depend on the form
of regulation, including transition mechanisms, if any, ultimately
adopted by the CPUC. Currently, the Company is unable to predict the
ultimate outcome of the electric industry restructuring or predict
whether such outcome will have a significant impact on its financial
position or results of operations.
Rate Matters:
- ------------
In addition to the OIR/OII, the RRI and the Long-Term Noncore Gas
Transportation Prices proposals discussed above, the following are
other rate-related matters.
1995 Electric Rate Stabilization/ARA: 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 retail 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 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. In addition, the Company has a five-
year goal of reducing its system-wide average electric rates.
In September 1994, the Company filed its ARA request for electric rates
effective January 1, 1995. In order to implement its electric rate
freeze in 1995, the Company proposes to forgo the electric rate
increase of approximately $170 million that otherwise would occur on
January 1, 1995, as authorized in the Company's 1993 GRC. In addition,
the Company proposes a decrease in base revenues equal to the increase
in revenues the CPUC approves in the Company's 1995 Cost of Capital,
ECAC, and the Helms Pumped Storage Project (Helms) proceedings, such
that electric rates will not increase through the end of 1995. The
CPUC could approve up to an estimated combined net electric revenue
requirement increase of $289 million in the Company's 1995 Cost of
Capital and ECAC proceedings and an additional $12 million related to
the Helms settlement.
As part of the electric rate freeze plan, the Company requested by a
separate filing, reductions of approximately $100 million in authorized
funding levels for 1995 electric customer energy efficiency (CEE)
programs and $17 million for electric research development and
demonstration (R&D) programs. However, the Company did not request
that the ARA filing and implementation of the electric rate freeze be
contingent upon the $117 million reduction in authorized funding levels
for those programs. If the CPUC grants the request, then the CEE and
R&D reductions would be part of, not in addition to, the ARA decreases
requested.
To the extent that the CPUC does not adopt the reduced CEE and R&D
authorized funding level or other cost reductions are not achieved,
there may be a negative impact on the Company's 1995 or 1996 results of
operations.
ECAC: In accordance with mechanisms established by the CPUC, the
Company accumulates the differences between actual costs of generating
electricity and the revenue designed to recover such costs. To the
extent costs exceed revenues, the undercollection accumulates in the
ECAC balancing account. Over the past few years, the Company has
experienced a significant increase in the level of balancing account
undercollection related to its electric energy costs. The increase
primarily results from Diablo Canyon's generation exceeding that
forecasted in the annual ECAC proceeding, increased fuel costs, the use
of higher-cost energy sources to compensate for less than normal hydro
conditions and the deferred recovery of undercollected balances.
Under the Company's 1995 electric rate freeze proposal, rate changes
adopted in the current ECAC proceeding and other electric proceedings
would be offset by reductions in the Company's base revenues. Although
the Company's proposal limits the requested recovery of the projected
December 31, 1994, ECAC undercollection by deferring recovery of $469
million beyond 1995, it does include collection of $238 million of the
undercollection. The filing also proposes to forgo collection of
interest on the ECAC deferral. As of September 30, 1994, the ECAC
balancing account undercollection was approximately $730 million.
In August 1994, the Company and the DRA submitted a joint
recommendation that included the Company's electric rate freeze
proposal discussed above and resolved most issues between the two
parties in the current ECAC proceeding. A proposed decision in this
proceeding is expected in December 1994.
Absent significant electric rate increases, recovery of the ECAC
undercollection would be dependent upon achieving extensive cost
reductions. In 1993 and 1994, the Company elected to defer, without
interest, recovery of the undercollection until such time as it could
implement sufficient cost reductions to facilitate recovery without
significantly increasing rates.
The ability of the Company to recover the ECAC balancing account
undercollection has been limited as a result of the Company's freeze on
retail electric rates. As previously indicated, the Company kept
retail electric rates flat in 1994, proposes to freeze such rates in
1995, and has a five-year goal of reducing its system-wide average
electric rates. The Company is pursuing various options to recover the
ECAC undercollection in a reasonable period of time. In the event that
none of these options result in the recovery of the ECAC
undercollection, the Company will have to write off some or all of the
ECAC undercollection.
Diablo Canyon Rate Case Settlement: In August 1994, the DRA filed a
petition which seeks to modify the CPUC's 1993 order refusing to
reconsider the Diablo Canyon rate case settlement. The DRA requests
that the CPUC modify its earlier decision for the purpose of reopening
the settlement to consider modification of the payment methodology
included in the settlement. In addition, the DRA recommends that the
price paid for electricity generated by Diablo Canyon be frozen at the
1994 price level of 11.89 cents per kilowatthour (kWh) which would
result in approximately $35 million reduction in the Company's 1995
revenue requirement request. The pricing formula set forth in the
settlement provides that the price paid for Diablo Canyon generation in
1995 be increased to approximately 12.1 cents per kWh. The DRA
requested expedited consideration by the CPUC of its petition.
In October 1994, an ALJ of the CPUC issued a ruling on the DRA's
petition. In his ruling, the ALJ indicated that he considers the DRA's
petition for modification as a motion (1) to set a hearing to modify
the pricing methodology included in the settlement and (2) to freeze
Diablo Canyon prices pending such a hearing. The ALJ rejected the
Company's assertion that since the DRA is a party to the settlement it
is barred from unilaterally recommending changes in the settlement and
cited regulatory authority recognizing the CPUC's ability to amend any
decision made by it. However, the ALJ indicated an unwillingness to
set a hearing on a case of such potential magnitude without additional
evidence on the issues. Accordingly, the ALJ's ruling sets for
December 1994, a hearing on the DRA's motion to set a hearing to modify
the Diablo Canyon pricing methodology and to freeze Diablo Canyon
prices pending such a hearing. The Company is evaluating various
alternatives in response to this development.
As a result of the Diablo Canyon rate case settlement and plant
performance, Diablo Canyon has provided an increasing percentage of the
Company's operating income. Either action of the CPUC in this
proceeding or restructuring of the electric industry may cause a
decline in the operating income generated by Diablo Canyon and/or the
results of operations of the Company.
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) gas rates effective July 15, 1994. During the
first half of the current BCAP period (November 1992-October 1993),
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.
In November 1994, the Company filed an application with the CPUC in its
1995 BCAP requesting a gas rate increase of approximately $173 million
annually for the two-year test period beginning October 1, 1995, and
ending September 30, 1997. The Company's request reflects a $53
million annual increase in procurement revenues and a $120 million
annual increase in transportation revenues. If the Company's request
is adopted, rates would be effective September 15, 1995. A final CPUC
decision is expected in the third quarter of 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/Return
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. 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 1, 1995.
In October 1994, the assigned ALJ issued a proposed decision in the
Company's 1995 Cost of Capital proceeding recommending a return on
common equity of 11.70 percent. Of the recommended return of 11.70
percent, .10 percent is intended to serve as compensation to investors
for the nondiversifiable risks associated with the timing of the
OIR/OII. The proposed decision authorizes a utility capital structure
of 48.00 percent common equity, 5.50 percent preferred stock and 46.50
percent long-term debt. When combined with the authorized costs of
debt and preferred stock, the 11.70 percent return on common equity
results in an overall return on utility rate base of 9.60 percent for
1995, compared with the 9.21 percent authorized for 1994. If adopted,
the proposed decision would increase revenue requirements by
approximately $70 million for electric rates and $22 million for gas
rates, effective January 1, 1995. However, consistent with the
Company's current electric rate freeze, the Company has proposed that
any electric revenue increase authorized in this proceeding be offset
by a decrease in base revenues, such that electric rates would not
increase through the end of 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 concurrently
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 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.
The DRA had recommended disallowances of $142 million and a penalty of
$50 million and indicated that it was considering additional
recommendations for these issues. The Company and the DRA have signed
settlement agreements to resolve for $68 million substantially all of
these recommended and potential disallowances, as well as the
recommended penalty.
To date, the Company has accrued $171 million ($61 million in the
fourth quarter of 1993 and approximately $90 and $20 million in the
first and third quarters of 1994, respectively) for gas reasonableness
matters. If the agreements between the Company and DRA are adopted by
the CPUC without modification, there will be no further financial
impact relating to issues covered by the agreements. The Company
believes that the ultimate resolution of any remaining reasonableness
matters will not have a significant adverse impact on the Company's
financial position or results of operations. As discussed above, the
Company intends to contest the CPUC's decision on the Canadian gas
disallowance for 1988 through 1990, the cost of which has been fully
accrued as part of the $171 million.
Legal Matters:
- -------------
In the normal course of business, the Company is named as a party in a
number of claims and litigation. Substantially all of these are
litigated or settled with no significant impact on either the Company's
results of operation or financial position.
There are several significant litigation cases which are discussed in
Note 4 of Notes to Consolidated Financial Statements. These cases
include claims for personal injury and property damage, as well as
punitive damages, allegedly suffered as a result of exposure to
chromium near the Company's Hinkley Compressor Station, antitrust
claims for damages as a result of purchasing natural gas in Canada by
the Company's wholly owned subsidiary and two cases claiming that the
Company underpaid franchise fees. The current status and the potential
financial impact of these cases are also discussed in Note 4.
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 capital structure provides financial flexibility and access
to capital markets at reasonable rates, ensuring the Company's ability
to meet all of its capital requirements.
In an effort to reduce financing costs, the Company continues to
redeem or reacquire higher-cost securities and issue securities with
lower dividend or interest rates. Proceeds from the issuance of
securities are 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 September
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 June 1994, PG&E Resources Company (Resources), a wholly
owned indirect subsidiary of Enterprises, entered into multiple
contracts to sell several of its oil and gas properties. In August
1994, Resources finalized the sales of those properties and
recognized a $21 million pretax gain, resulting in a $2 million year-
to-date net pretax gain.
In July 1994, the Company's board of directors approved a plan for the
disposition in 1994 or early 1995 of Resources, if market conditions
remain favorable. The disposition, if completed, is not anticipated to
have a significant impact on the Company's financial position or
results of operations.
As discussed above in the Proposed Accounting Standard section, the
FASB may adopt a new standard related to the impairment of long-lived
assets. If the standard is adopted as proposed, the result would be an
impairment of the carrying value of the Company's investment in proved
oil and gas properties of approximately $100 million.
Acquisition: In August 1994, Enterprises and Bechtel Enterprises
completed their acquisition of J. Makowski Co., Inc. (JMC), a Boston-
based company engaged in the development of natural gas-fueled power
generation projects and natural gas distribution, supply and
underground storage projects. The final purchase price was
approximately $250 million. Enterprises' effective ownership share of
JMC is approximately 78 percent.
PART II. OTHER INFORMATION
- ---------------------------
Item 1. Legal Proceedings
-----------------
A. Antitrust Litigation
As previously reported in the Company's Form 10-K for the fiscal
year ended December 31, 1994, in December 1993, the County of
Stanislaus, California, and a residential customer of the
Company, filed a complaint against the Company and Pacific Gas
Transmission Company (PGT), a subsidiary of the Company, on
behalf of themselves and purportedly as a class action on behalf
of all natural gas customers of the Company during the period of
February 1988 through October 1993. The complaint alleged that
the purchase of natural gas in Canada was accomplished in
violation of various antitrust laws which resulted in increased
prices of natural gas for the Company's customers.
As reported in a Current Report on Form 8-K dated September 12,
1994, on August 25, 1994, the federal district court in Fresno,
California issued a decision granting the Company's motion to
dismiss the federal and state antitrust claims and the state
unfair practices claims against the Company and PGT and granting
plaintiffs' motion seeking class certification. In dismissing
the antitrust claims, the Court determined that the prices the
Company paid for Canadian gas had been filed with, reviewed and
approved as reasonable by various federal and state regulatory
authorities, and as a result, the plaintiffs were barred from
claiming that those rates were too high. The Court also held
that the California Public Utilities Commission's (CPUC)
oversight of the Company's gas acquisition costs constitutes
state action which immunizes the Company from a private antitrust
lawsuit such as this one.
The plaintiffs were given 10 days to amend their complaint to
state a new claim and on September 9, 1994 they filed an amended
complaint with the Court. Alberta and Southern Gas Co. Ltd., the
Company's wholly owned Canadian gas purchasing subsidiary, is
added as a defendant in the amended complaint. In essence, the
amended complaint restates the claims in the original complaint,
and in addition alleges that the defendants, through
anticompetitive practices, foreclosed access over the PGT
pipeline to alternative sources of gas in Canada by certain
customers of the Company. A new motion to dismiss was filed by
the Company on November 7, 1994.
The Company believes that the ultimate outcome of this matter
will not have a significant adverse impact on its financial
position.
B. Hinkley Litigation
As previously reported in a Current Report on Form 8-K dated
September 22, 1994, the Company has reached an agreement relating
to a settlement of litigation filed in the San Bernadino 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 Company has reached an agreement with plaintiffs' counsel and
over 90% of the identified 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 those plaintiffs. Under the terms of the
agreement, the Company will pay an aggregate amount of no more
than $400 million in settlement of such plaintiffs' claims,
including $50 million paid to escrow to date. In turn, those
plaintiffs, and their attorneys, agree to indemnify the Company
against any additional losses the Company 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 identified plaintiffs in connection with the alleged
chromium contamination. As of September 30, 1994, the Company
has a remaining reserve of $50 million against any future
potential liability in this case.
Although the Company is not able to estimate the amount of loss
it will ultimately incur in connection with this matter, the
ultimate outcome of this matter 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.
C. Time-Of-Use Meter Litigation
As previously reported in the Company's Form 10-Q for the
quarterly period ended June 30, 1994, in July 1994 five
individuals 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
(focusing, in particular, on the "time-of-use" billing option)
and seeks damages estimated to be in excess of $16 billion.
On August 11, 1994, the plaintiffs filed an amended complaint.
The amended complaint broadens the alleged class to include
customers of the Turlock Irrigation District (TID), which
purchases power from the Company, on the theory that TID
customers' rates have been affected by the Company's alleged
failure to notify its customers of the best available rate. The
amended complaint also adds a claim for $100 billion in
"exemplary" damages, alleging that the Company's failure to
properly advise customers of the "time-of-use" billing option and
other rates was "wilful".
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.
D. Potter Valley Hydroelectric Project
In April 1994, the Federal Energy Regulatory Commission (FERC)
issued an order (April Order) approving the design of a fish
screen and bypass facility for the Company's Potter Valley
Hydroelectric Project (Potter Valley). On September 7, 1994, the
FERC issued a Compliance Order (Compliance Order) which indicated
that the Company was in violation of the April Order and the FERC
license to operate Potter Valley. The Compliance Order cited as
the basis for such violation a letter sent by the Company to the
FERC in May 1994, in which the Company indicated it was
suspending plans to install the fish screen facility at Potter
Valley. The Company subsequently commenced construction of the
fish screen by September 27, 1994 as required by the Compliance
Order. It is the Company's position that its actions did not
violate the April Order or the FERC license to operate Potter
Valley.
The FERC is authorized to impose fines of up to $10,000 per day
for violations of FERC hydroelectric licenses or related orders.
It is not known at present whether the FERC will impose a fine in
connection with the violation cited in the Compliance Order or
what the amount of any such fine might be.
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 nine months
ended September 30, 1994 was 4.08. The Company's earnings to
combined fixed charges and preferred stock dividends ratio for
the nine months ended September 30, 1994 was 3.57. Statements
setting forth the computation of the foregoing ratios are filed
herewith as Exhibits 12.1 and 12.2 to Registration Statement Nos.
33-62488, 33-64136 and 33-50707.
Item 6. Exhibits and Reports on Form 8-K
---------------------------------
(a) Exhibits:
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to
Fixed Charges
Exhibit 12.2 Computation of Ratios of Earnings to
Combined Fixed Charges and Preferred
Stock Dividends
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K during the third quarter of 1994 and
through the date hereof:
1. 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
2. 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
3. August 3, 1994
Item 5. Other Events
A. California Public Utilities Commission Proceedings
- 1995 Electric Rate Stabilization
4. September 12, 1994
Item 5. Other Events
A. 1995 Electric Rate Stabilization/attrition Rate
Adjustment
B. 1994 Workforce Reduction
C. Diablo Canyon Nuclear Power Plant - Diablo Canyon
Rate Case Settlement
D. Antitrust Litigation
5. September 22, 1994
Item 5. Other Events
A. Hinkley Litigation
6. October 13, 1994
Item 5. Other Events
A. Helms Pumped Storage Plant - Proposed Settlement
7. October 21, 1994
Item 5. Other Events
A. Diablo Canyon Nuclear Power Plant - Diablo Canyon
Rate Case Settlement
B. Performance Incentive Plan - Year-to-Date
Financial Results
8. October 28, 1994
A. California Public Utilities Commission Proceeding
- 1995 Cost of Capital Proceeding
- Long-Term Noncore Gas Transportation Tariff
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
November 10, 1994 By______________________________
GORDON R. SMITH
Vice President and
Chief Financial Officer
<TABLE>
EXHIBIT 11
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
-------------------- --------------------
(in thousands, except per share amounts) 1994 1993 1994 1993
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income $425,633 $356,099 $903,950 $857,113
Less preferred dividends 14,494 15,520 43,314 48,913
Net income for calculating EPS for -------- -------- -------- --------
Statement of Consolidated Income $411,139 $340,579 $860,636 $808,200
======== ======== ======== ========
Average common shares outstanding 430,439 432,472 429,584 430,527
======== ======== ======== ========
EPS as shown in the Statement of
Consolidated Income $ .96 $ .79 $ 2.00 $ 1.88
======== ======== ======== ========
PRIMARY EPS (1)
Net income $425,633 $356,099 $903,950 $857,113
Less preferred dividends 14,494 15,520 43,314 48,913
-------- -------- -------- --------
Net income for calculating primary EPS $411,139 $340,579 $860,636 $808,200
======== ======== ======== ========
Average common shares outstanding 430,439 432,472 429,584 430,527
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) 443 1,895 572 1,544
-------- -------- -------- --------
Average common shares outstanding as
adjusted 430,882 434,367 430,156 432,071
======== ======== ======== ========
Primary EPS $ .95 $ .78 $ 2.00 $ 1.87
======== ======== ======== ========
FULLY DILUTED EPS (1)
Net income $425,633 $356,099 $903,950 $857,113
Less preferred dividends 14,494 15,520 43,314 48,913
-------- -------- -------- --------
Net income for calculating fully diluted EPS $411,139 $340,579 $860,636 $808,200
======== ======== ======== ========
Average common shares outstanding 430,439 432,472 429,584 430,527
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) 443 1,985 572 1,985
-------- -------- -------- --------
Average common shares outstanding as
adjusted 430,882 434,457 430,156 432,512
======== ======== ======== ========
Fully diluted EPS $ .95 $ .78 $ 2.00 $ 1.87
======== ======== ======== ========
- --------------------------------------------------------------------------------------------
<F/N>
(1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K.
This presentation is not required by APB Opinion No. 15, because it results in dilution
of less than 3%.
</TABLE>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) 9/30/94 1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 903,950 $1,065,495 $1,170,581 $1,026,392 $ 987,170 $ 900,628
Company's equity in
undistributed loss
(earnings) of
unconsolidated
affiliates - - (3,349) 26,671 (2,799) (4,352)
Income tax expense 736,189 901,890 895,126 851,534 881,647 669,885
Net fixed charges 531,096 730,708 758,333 760,957 788,889 821,982
-------- ---------- ---------- ---------- ---------- ----------
Total Earnings $2,171,235 $2,698,093 $2,820,691 $2,665,554 $2,654,907 $2,388,143
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 470,273 $ 642,408 $ 696,765 $ 682,811 $ 677,476 $ 712,607
Interest on short-
term debt 60,465 87,819 61,182 77,760 110,982 108,869
Interest on capital
leases 1,302 1,737 1,737 1,737 1,737 1,737
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $ 532,040 $ 731,964 $ 759,684 $ 762,308 $ 790,195 823,213
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 4.08 3.69 3.71 3.50 3.36 2.90
- ---------------------------------------------------------------------------------------------------
<F/N>
Note: For the purpose of computing the Company's ratios of earnings to fixed charges,
"earnings" represent net income adjusted for the Company's equity in undistributed
earnings or loss of unconsolidated affiliates, income taxes and fixed charges
(excluding capitalized interest). "Fixed charges" consist of interest on short-term
and long-term debt (including amortization of bond premium, discount and expense; and
excluding interest on decommissioning trust funds [for which an equal amount of
interest income is recorded] and amortization of the gain or loss on reacquired debt
securities) and interest on capital leases (including capitalized interest).
</TABLE>
<TABLE>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) 9/30/94 1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 903,950 $1,065,495 $1,170,581 $1,026,392 $ 987,170 $ 900,628
Company's equity in
undistributed loss
(earnings) of
unconsolidated
affiliates - - (3,349) 26,671 (2,799) (4,352)
Income tax expense 736,189 901,890 895,126 851,534 881,647 669,885
Net fixed charges 531,096 730,708 758,333 760,957 788,889 821,982
-------- ---------- ---------- ---------- ---------- ----------
Total Earnings $2,171,235 $2,698,093 $2,820,691 $2,665,554 $2,654,907 $2,388,143
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 470,273 $ 642,408 $ 696,765 $ 682,811 $ 677,476 $ 712,607
Interest on short-
term debt 60,465 87,819 61,182 77,760 110,982 108,869
Interest on capital
leases 1,302 1,737 1,737 1,737 1,737 1,737
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 532,040 731,964 759,684 762,308 790,195 823,213
---------- ---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 3,504 4,814 5,136 5,136 5,136 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 72,232 108,937 130,147 154,404 175,881 167,440
---------- ---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 75,736 113,751 135,283 159,540 181,017 172,576
---------- ---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and
Preferred Stock
Dividends $ 607,776 $ 845,715 $ 894,967 $ 921,848 $ 971,212 $ 995,789
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed
Charges and Preferred
Stock Dividends 3.57 3.19 3.15 2.89 2.73 2.40
- ---------------------------------------------------------------------------------------------------
<F/N>
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 Company's equity in undistributed earnings or loss of unconsolidated affiliates,
income taxes and fixed charges (excluding capitalized interest). "Fixed charges"
consist of interest on short-term and long-term debt (including amortization of bond
premium, discount and expense; and excluding interest on decommissioning trust funds
[for which an equal amount of interest income is recorded] and amortization of the
gain or loss on reacquired debt securities) and interest on capital leases (including
capitalized interest). "Preferred stock dividends" represent the sum of requirements
for preferred stock dividends that are deductible for federal income tax purposes and
requirements for preferred stock dividends that are not 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> 1000
<S> <C>
<PERIOD-TYPE> 9-MOS
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<PERIOD-END> SEP-30-1994
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137,500
732,995
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0
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43,314
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</TABLE>
