FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
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(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File No. 1-2348
PACIFIC GAS AND ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
California 94-0742640
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(State or other jurisdiction of (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 April 28, 1995
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Common Stock, $5 par value 428,589,308 shares
Form 10-Q
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TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION Page
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Item 1. Consolidated Financial Statements and Notes
Statement of Consolidated Income................... 1
Consolidated Balance Sheet......................... 2
Statement of Consolidated Cash Flows............... 4
Note 1: General
Basis of Presentation................... 5
Workforce Reductions.................... 5
Note 2: Electric Industry Restructuring........... 6
Note 3: Gas Reasonableness Proceedings............ 8
Note 4: Diablo Canyon............................. 9
Note 5: New Accounting Standard................... 9
Note 6: Contingencies
Nuclear Insurance....................... 10
Environmental Remediation............... 10
Legal Matters........................... 11
Item 2. Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Competition and Changing Regulatory Environment.... 14
Results of Operations
Earnings Per Common Share........................ 16
Common Stock Dividend............................ 16
Operating Revenues............................... 16
Operating Expenses............................... 17
Other Income and (Income Deductions)............. 17
Regulatory Matters............................... 17
Nonregulated Operations.......................... 19
Liquidity and Capital Resources
Sources of Capital............................... 20
Risk Management.................................. 20
Investing and Financing Activity................. 20
Environmental Remediation........................ 21
Legal Matters.................................... 21
Other Matters
New Accounting Standard.......................... 21
Accounting for Decommissioning Expense........... 22
PART II. OTHER INFORMATION
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Item 4. Submission of Matters to a Vote of Security-Holders.. 23
Item 5. Other Information
Open Access Tariffs for Wholesale Electric
Transmission..................................... 24
Management Changes................................. 24
Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed Charges
and Preferred Stock Dividends.................... 25
Item 6. Exhibits and Reports on Form 8-K..................... 25
SIGNATURE...................................................... 27
PART 1. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
---------------------------------
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(unaudited)
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Three months ended March 31,
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(in thousands, except per share amounts) 1995 1994
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OPERATING REVENUES
Electric $1,696,244 $1,815,977
Gas 543,741 644,188
Other 67,366 54,106
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Total operating revenues 2,307,351 2,514,271
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OPERATING EXPENSES
Cost of electric energy 438,845 591,152
Cost of gas 103,563 261,386
Distribution 41,518 57,063
Transmission 66,755 72,692
Customer accounts and services 100,494 90,114
Maintenance 92,040 113,656
Depreciation and decommissioning 352,183 348,433
Administrative and general 261,121 195,169
Workforce reduction costs (18,195) -
Income taxes 265,498 249,710
Property and other taxes 73,869 80,815
Other 64,793 39,407
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Total operating expenses 1,842,484 2,099,597
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OPERATING INCOME 464,867 414,674
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OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 15,326 10,774
Allowance for equity funds used during construction 5,638 4,679
Other--net 16,905 (8,363)
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Total other income and (income deductions) 37,869 7,090
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INCOME BEFORE INTEREST EXPENSE 502,736 421,764
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INTEREST EXPENSE
Interest on long-term debt 162,149 155,724
Other interest charges 14,776 33,075
Allowance for borrowed funds used during construction (2,876) (3,987)
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Net interest expense 174,049 184,812
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NET INCOME 328,687 236,952
Preferred dividend requirement 14,494 14,458
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EARNINGS AVAILABLE FOR COMMON STOCK $ 314,193 $ 222,494
========== ==========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 430,086 428,531
EARNINGS PER COMMON SHARE $.73 $.52
DIVIDENDS DECLARED PER COMMON SHARE $.49 $.49
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
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March 31, December 31,
(in thousands) 1995 1994
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ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $17,119,479 $17,045,247
Diablo Canyon 6,657,064 6,647,162
Gas 7,571,191 7,447,879
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Total plant in service (at original cost) 31,347,734 31,140,288
Accumulated depreciation and decommissioning (12,588,825) (12,269,377)
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Net plant in service 18,758,909 18,870,911
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CONSTRUCTION WORK IN PROGRESS 526,570 527,867
OTHER NONCURRENT ASSETS
Oil and gas properties 424,377 437,352
Nuclear decommissioning funds 641,791 616,637
Investment in nonregulated projects 781,327 761,355
Other assets 142,244 137,325
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Total other noncurrent assets 1,989,739 1,952,669
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CURRENT ASSETS
Cash and cash equivalents 392,741 136,900
Accounts receivable
Customers 1,205,121 1,413,185
Other 89,723 98,035
Allowance for uncollectible accounts (32,284) (29,769)
Regulatory balancing accounts receivable 1,126,769 1,345,669
Inventories
Materials and supplies 202,860 197,394
Gas stored underground 108,948 136,326
Fuel oil 53,008 67,707
Nuclear fuel 136,933 140,357
Prepayments 36,744 33,251
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Total current assets 3,320,563 3,539,055
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DEFERRED CHARGES
Income tax-related deferred charges 1,166,400 1,155,421
Diablo Canyon costs 396,668 401,110
Unamortized loss net of gain on reacquired debt 380,097 382,862
Workers' compensation and disability claims recoverable 247,065 247,209
Other 688,615 732,029
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Total deferred charges 2,878,845 2,918,631
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TOTAL ASSETS $27,474,626 $27,809,133
=========== ===========
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<FN>
(continued on next page)
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
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March 31, December 31,
(in thousands) 1995 1994
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CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,142,750 $ 2,151,213
Additional paid-in capital 3,820,650 3,806,508
Reinvested earnings 2,716,339 2,677,304
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Total common stock equity 8,679,739 8,635,025
Preferred stock without mandatory redemption provisions 732,995 732,995
Preferred stock with mandatory redemption provisions 137,500 137,500
Long-term debt 8,512,035 8,675,091
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Total capitalization 18,062,269 18,180,611
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OTHER NONCURRENT LIABILITIES
Customer advances for construction 152,511 152,384
Workers' compensation and disability claims 221,200 221,200
Other 800,164 644,233
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Total other noncurrent liabilities 1,173,875 1,017,817
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CURRENT LIABILITIES
Short-term borrowings 142,439 524,685
Long-term debt 493,691 477,047
Accounts payable
Trade creditors 377,735 414,291
Other 336,805 337,726
Accrued taxes 682,780 436,467
Deferred income taxes 327,183 432,026
Interest payable 159,787 84,805
Dividends payable 225,558 210,903
Other 398,946 643,779
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Total current liabilities 3,144,924 3,561,729
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DEFERRED CREDITS
Deferred income taxes 3,955,091 3,902,645
Deferred investment tax credits 386,949 391,455
Noncurrent balancing account liabilities 157,737 226,844
Other 593,781 528,032
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Total deferred credits 5,093,558 5,048,976
CONTINGENCIES (Notes 2, 3 and 6)
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TOTAL CAPITALIZATION AND LIABILITIES $27,474,626 $27,809,133
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
(unaudited)
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Three months ended March 31,
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(in thousands) 1995 1994
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CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 328,687 $ 236,952
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and decommissioning 352,183 348,433
Amortization 33,316 27,922
Deferred income taxes and investment tax credits--net (65,603) (7,870)
Allowance for equity funds used during construction (5,638) (4,679)
Other deferred charges (17,450) 29,058
Other noncurrent liabilities 169,264 4,944
Noncurrent balancing account liabilities and
other deferred credits (3,358) 120,525
Net effect of changes in operating assets
and liabilities
Accounts receivable 218,891 144,345
Other working capital (173,181) (28,656)
Regulatory balancing accounts receivable 218,900 (81,860)
Inventories 36,611 60,544
Accounts payable (37,477) (80,588)
Accrued taxes 246,313 211,585
Other-net 45,827 (4,132)
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Net cash provided by operating activities 1,347,285 976,523
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CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures (197,051) (235,253)
Allowance for borrowed funds used during construction (2,876) (3,987)
Nonregulated expenditures (34,640) (29,300)
Other--net (43,207) 29,790
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Net cash used by investing activities (277,774) (238,750)
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CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 66,871 61,548
Common stock repurchased (110,316) (553)
Preferred stock issued - 62,312
Preferred stock redeemed - (82,965)
Long-term debt issued - 20,485
Long-term debt matured or reacquired (149,250) (125,627)
Short-term debt redeemed--net (382,246) (372,090)
Dividends paid (225,875) (217,910)
Other--net (12,854) 37,923
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Net cash used by financing activities (813,670) (616,877)
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NET CHANGE IN CASH AND CASH EQUIVALENTS 255,841 120,896
CASH AND CASH EQUIVALENTS AT JANUARY 1 136,900 61,066
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CASH AND CASH EQUIVALENTS AT MARCH 31 $ 392,741 $ 181,962
========= ==========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 89,689 $ 92,088
Income taxes 43,975 67,758
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
NOTE 1: GENERAL
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Basis of Presentation:
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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. This information should be read in conjunction with
the Consolidated Financial Statements and Notes to Consolidated
Financial Statements incorporated by reference in the 1994 Annual
Report on Form 10-K.
In the opinion of management, the accompanying statements reflect all
adjustments which are necessary to present a fair statement of the
financial position and results of operations for the interim periods.
All material adjustments are of a normal recurring nature unless
otherwise disclosed in this Form 10-Q. Prior year's amounts in the
consolidated financial statements have been reclassified where
necessary to conform to the 1995 presentation. Results of operations
for interim periods are not necessarily indicative of results to be
expected for a full year.
Workforce Reductions:
- --------------------
In April 1995, the Company canceled approximately 800 planned
severances in order to accelerate maintenance on its system in light of
the severity of the damage caused by recent storms and the
identification of certain facilities that would benefit from a more
extensive and accelerated maintenance program. In March 1995, the
Company reversed $18.2 million of the estimated severance costs of $61
million accrued and expensed in 1994. Due to the extensive maintenance
work required, operating expenses for the remainder of 1995 are
expected to be higher than originally planned.
Through March 31, 1995, $19 million of severance benefits were paid and
charged against the liability relating to approximately 500 actual
severances. The remaining job reductions will be accomplished by
severance and attrition over the remainder of 1995. The majority of
the severances are in generation and transmission functions.
Approximately 1,500 reductions had already been accomplished in 1994
through a voluntary retirement incentive at a cost of $188 million.
The Company does not plan to seek rate recovery for the cost of the
1994-1995 workforce reductions.
NOTE 2: Electric Industry Restructuring
- ----------------------------------------
In April 1994, the California Public Utilities Commission (CPUC) issued
an order instituting a rulemaking and investigation (OIR/OII) on
electric industry restructuring. The proposal, which is subject to
comment and modification, seeks to lower energy prices and provide
customers with a choice of electric generation suppliers (known as
direct access). This proposal involves two key strategies: phase in
direct access to electric generation for all customers over a six-year
period beginning in 1996, and where competition does not exist, replace
traditional cost-of-service regulation with performance-based
regulation. Utilities would still be obligated to provide transmission
and distribution services to all customers.
To ensure an orderly transition to a competitive market that maintains
the financial integrity of the utilities, the CPUC proposed that
uneconomic costs of utility generating assets (i.e., costs which are
above market and could not be recovered under market-based pricing) be
recovered through a "competition transition charge" (CTC). However,
the OIR/OII did not specify which costs might be recovered through such
a transition charge or 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. 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.
In November 1994, the Company filed testimony with the CPUC on its plan
for recovering lost revenues associated with uneconomic assets and
obligations resulting from the restructuring of the electric industry
as proposed by the CPUC. The Company's testimony, among other things,
identifies and defines the costs proposed to be included in the CTC,
provides preliminary estimates of the lost revenues and discusses
options for allocating and recovering the CTC. Based on assumed market
prices of $.048 and $.032 per kilowatthour (kWh), the Company estimated
that its CTC would be approximately $3 billion and $11 billion,
respectively. The Company identified three categories of uneconomic
assets: utility-owned generation assets and power purchase
commitments, power purchase obligations relating to Qualifying
Facilities (QFs), and generation-related regulatory assets. The
estimates of the CTC were determined by comparing future revenue
requirements of generation assets and power purchase obligations, over
a twenty-year and thirty-year period, respectively, with revenues
computed at assumed market prices. Diablo Canyon Nuclear Power Plant
(Diablo Canyon) was included in the revenue requirement calculation
using the proposed pricing modification to the Diablo Canyon settlement
(See Note 4 of Notes to Consolidated Financial Statements.) The
revenue requirement for Diablo Canyon and all Company-owned generation
assets included a return on investment. The actual amount of
uneconomic assets and obligations will depend upon the final form of
regulatory changes adopted by the CPUC and the actual market price of
electricity. CTC recovery less than the amount estimated by the
Company will not equate to the loss, if any, the Company may record as
a result of the electric industry restructuring. See "Financial Impact
of the Electric Industry Restructuring Proposal" below.
Under the Company's proposal for a longer phase-in period to direct
access, the Company would not seek recovery of the transition costs
associated with its own generation assets and power purchase
commitments, except for commitments to purchase power from QFs and
regulatory assets. Based on the longer phase-in period and the market
price assumptions referred to above, the CTC would be approximately $3
billion and $5 billion, respectively. If the CPUC adopts a shorter
phase-in period, the Company indicated that it would seek recovery
through the CTC of all lost revenues resulting from the restructuring.
The CPUC was scheduled to propose a policy decision on March 22, 1995,
with a final policy decision to be effective no earlier than September
1995. However, in March 1995, the CPUC announced that it was
postponing issuance of its proposed policy statement to allow
additional time for analysis of the extensive record developed in the
OIR/OII. It is expected that the CPUC's proposed policy statement,
when it is issued, will be subject to hearings and state legislative
review before it can be implemented.
Financial Impact of the Electric Industry Restructuring Proposal:
Based on the regulatory framework in which it operates, the Company
currently accounts for the economic effects of regulation in accordance
with the provisions of Statement of Financial Accounting Standards
(SFAS) No. 71, "Accounting for the Effects of Certain Types of
Regulation." As a result of applying the provisions of SFAS No. 71,
the Company has accumulated approximately $3.5 billion of regulatory
assets, including balancing accounts, at March 31, 1995.
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 its operations. The Company
continues to evaluate 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 of approximately $500 million which are expected to be
recovered in the near term, were approximately $1.6 billion at March
31, 1995. This amount could vary depending on the allocation methods
used.
The electric industry restructuring and transition to a competitive
environment may also adversely impact the Company's returns on its
investments in utility generation assets and the recoverability of
certain other costs, including QF power purchase obligations. In the
event that recovery of these costs and investments, through the CTC or
otherwise, becomes unlikely, the Company would write off applicable
portions of the generation assets and record a charge to earnings
related to the recovery of other costs. The book value of the
Company's generation assets, excluding Diablo Canyon, was approximately
$2.7 billion at March 31, 1995. The net book value of the Company's
investment in Diablo Canyon was approximately $5.1 billion at March 31,
1995.
The financial impact of the electric industry restructuring will depend
on the form of regulation, including transition mechanisms, if any,
adopted by the CPUC and the groups of customers affected. 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.
NOTE 3: Gas Reasonableness Proceedings
- ---------------------------------------
Recovery of energy costs through the Company's regulatory balancing
account mechanisms is subject to a CPUC determination that such costs
were reasonable. Under the current regulatory framework, annual
reasonableness proceedings are conducted by the CPUC on a historic
calendar year basis.
In March 1994, the CPUC issued decisions covering the years 1988
through 1990, ordering disallowances of approximately $90 million of
gas costs, plus accrued interest of approximately $25 million through
1993 for the Company's Canadian gas procurement activities, and $8
million for gas inventory operations. The Company has filed a lawsuit
in a federal district court challenging the CPUC decision on Canadian
gas costs. In February 1995, the CPUC filed a motion to dismiss the
lawsuit. A federal ruling on the CPUC's motion is expected later in
1995.
In March 1995, the CPUC approved a $.5 million settlement agreement
between the Division of Ratepayer Advocates (DRA) and the Company which
resolves $11.4 million of DRA recommended disallowances relating to
non-Canadian gas issues arising from the 1991 record period.
A number of other reasonableness issues related to the Company's gas
procurement practices, transportation capacity commitments and supply
operations for periods dating from 1988 to 1994 are still under review
by the CPUC. The DRA recommended disallowances of $131 million and a
penalty of $50 million and indicated that it was considering additional
recommendations for pending issues. The Company and the DRA have
signed settlement agreements to resolve most of these issues for a $68
million disallowance.
Significant issues covered by the settlement agreements include (1) the
Company's purchases of Canadian gas in 1991 and 1992 for its electric
department and its core customers from 1991 through May 1994; (2) the
Company's purchase of Southwest and California gas for its core
customers from 1992 through May 1994; (3) the investigation by the DRA
of Alberta and Southern Gas Co. Ltd. (A&S) and proposed investigation
of Alberta Natural Gas Company Ltd. for the period 1988 through May
1994; (4) the effects of Canadian gas prices on amounts paid by the
Company for Northwest power purchases for 1988 through 1992 and power
from QFs and geothermal producers for 1991 and 1992; (5) the Company's
gas storage operations for 1992; (6)the Company's Southwest gas
procurement activities for 1988 through 1990; and (7) Canadian gas
restructuring transition costs billed to PG&E by Pacific Gas
Transmission Company (PGT).
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: The Company has
accrued approximately $196 million for gas reasonableness matters, of
which $90 million was recorded in the first quarter of 1994 . Such
accruals include the CPUC decisions for the years 1988 through 1990 and
issues covered by the settlement agreements. The Company believes the
ultimate outcome of these matters will not have a significant impact on
its financial position or results of operations.
NOTE 4: Diablo Canyon
- ----------------------
In December 1994, the Company, the DRA, the California Attorney General
and several other parties representing energy consumers agreed to
modify the pricing provisions of the 1988 Diablo Canyon rate case
settlement. The modification, which is subject to CPUC approval, calls
for a reduction in the price paid for electricity generated by Diablo
Canyon over the next five years.
In the three-month period ended March 31, 1995, the Company recognized
Diablo Canyon revenues based on the proposed modified pricing. Diablo
Canyon revenues were approximately $464 million for the three-month
period ended March 31, 1995, which is approximately $45 million less
than would have been recorded under the pricing of the original
settlement. Agreements with the DRA or other parties do not constitute
a CPUC decision and are subject to modification by the CPUC in its
final decision.
NOTE 5: New Accounting Standard
- --------------------------------
The Financial Accounting Standards Board has issued Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of." The Company must adopt SFAS No. 121 by January 1, 1996,
but may elect to adopt it earlier.
The general provisions of SFAS No. 121 require, among other things,
that the existence of an impairment be evaluated whenever events or
changes in circumstances indicate that the carrying amount of an asset
may not be fully recoverable, and prescribe standards for the
recognition and measurement of impairment losses. In addition, SFAS
No. 121 requires that regulatory assets continue to be probable of
recovery in rates, rather than only at the time the regulatory asset is
recorded. Regulatory assets currently recorded may be written off if
recovery is no longer probable. The Company cannot predict the effect
the electric industry restructuring, discussed in Note 2, will have on
the recovery of its generation-related regulatory assets. Accordingly,
the Company cannot predict whether the adoption of this standard will
have a significant impact on its financial position or results of
operations.
NOTE 6: Contingencies
- ----------------------
Nuclear Insurance:
- -----------------
The Company is a member of Nuclear Mutual Limited (NML) and Nuclear
Electric Insurance Limited (NEIL). Under these policies, if the
nuclear plant of a member utility is damaged or the member incurs
costs beyond those covered by insurance for business interruption due
to a prolonged accidental outage, the Company may be subject to
maximum assessments of $28 million (property damage) and $7 million
(business interruption), in each case per policy period, in the event
losses exceed the resources of NML or NEIL.
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 $8.9 billion per incident. Coverage of the first $200
million is provided by a pool of commercial insurers. If a nuclear
incident results in 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. The
Company has an accrued liability at March 31, 1995, of $99 million
for hazardous waste remediation costs. The costs may be as much as
$240 million 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 or
necessary remediation is greater than anticipated at sites for which
the Company is responsible.
The Company will seek recovery of prudently incurred hazardous waste
compliance and remediation costs through ratemaking procedures
approved by the CPUC. The Company believes 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: A lawsuit was filed by the County of
Stanislaus, California, and a residential customer of the Company 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 lawsuit 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 were 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. The
court has granted the plaintiffs' motion seeking class certification.
A federal district court has granted the Company's motion to dismiss
the federal and state antitrust claims and the state unfair practices
claims against the Company and PGT. The plaintiffs have 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 a state
superior court on behalf of individuals seeking recovery of an
unspecified amount of damages for personal injuries and property
damage allegedly suffered as a result of exposure to chromium near
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.
The Company has reached an agreement with plaintiffs pursuant to
which those plaintiffs' actions will be submitted to binding
arbitration for resolution of issues concerning the cause and extent
of any damages suffered by plaintiffs as a result of the alleged
chromium contamination. Under the terms of the agreement, the
Company will pay an aggregate amount of no more than $400 million in
settlement of such plaintiffs' claims. In turn, those plaintiffs,
and their attorneys, agree to indemnify 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 March 31, 1995, the Company has paid $50 million to escrow and
reserved an additional $100 million against any future potential
liability in this case. The Company believes the ultimate outcome of
this matter will not have a significant adverse impact on its
financial position or results of operations.
Counties Franchise Fees Litigation: In March 1994, the Counties of
Alameda and Santa Clara filed a complaint in Superior Court against
the Company on behalf of themselves and purportedly as a class action
on behalf of 47 counties with which the Company has gas or electric
franchise contracts. Franchise contracts require the Company to pay
fees on an annual basis to cities and counties for the right to use
or occupy public streets and roads. The complaint alleges that,
since at least 1987, the Company has intentionally underpaid its
franchise fees to the counties in an unspecified amount.
The complaint cites two reasons for the alleged underpayment of fees.
Based on their interpretation of certain legislation, the plaintiffs
allege that the Company has been using the wrong methodology to
compute the franchise fees payable to the plaintiff counties. The
plaintiffs also allege that fees have been underpaid due to incorrect
calculations under the methodology used by the Company.
The parties stipulated to this case proceeding as a class action
lawsuit regarding the issue of the correct payment methodology to be
applied in calculating the franchise fees due to the plaintiffs. In
March 1995, the Superior Court granted the Company's motion for
summary judgment in the class action lawsuit. The plaintiffs have
until mid-June to appeal that ruling.
Should the counties appeal and be successful on the issue of
franchise fee calculation methodology, the Company's annual
systemwide county franchise fees could increase by approximately $15
million. Damages for alleged underpayments in prior years could be
as much as $117 million (exclusive of interest estimated to be $28
million as of March 31, 1995).
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.
Cities Franchise Fees Litigation: In May 1994, the City of Santa
Cruz filed a complaint in Superior Court against the Company on
behalf of itself and purportedly as a class action on behalf of 107
cities with which the Company has certain electric franchise
contracts. The complaint alleges that, since at least 1988, the
Company has intentionally underpaid its franchise fees to the cities
in an unspecified amount.
The complaint alleges that the Company has asked for and accepted
electric franchises from the cities included in the purported class,
which provide for lower franchise payments than required by
franchises granted by other cities in the Company's service
territory. The complaint also alleges that the transfer of these
franchises to the Company by its predecessor companies was not
approved by the CPUC as required, and therefore, all such franchise
contracts are void.
The Court has certified the class of 107 cities in this action and
approved the City of Santa Cruz as the class representative. The
case is in discovery and set for trial in October 1995.
Should the cities prevail on the issue of franchise fee calculation
methodology, the Company's annual systemwide city electric franchise
fees could increase by approximately $17 million. Damages for
alleged underpayments in prior years could be as much as $114 million
(exclusive of interest, estimated to be $25 million as of March 31,
1995).
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
---------------------------------------------
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). The Company is engaged principally in the business of
supplying electric and natural gas service throughout most of Northern
and Central California. The Company's operations are regulated by the
California Public Utilities Commission (CPUC) and the Federal Energy
Regulatory Commission (FERC), among others.
Competition and Changing Regulatory Environment:
- -----------------------------------------------
The energy utility industry continues to move toward a more competitive
environment. The Company is faced with many challenges and has taken
several significant actions to position itself to compete effectively
in the restructured utility industry. However, to date, competition
has not had a significant impact on the Company's consolidated results
of operations. In addition, there have been delays in instituting the
regulatory reforms necessary to open markets to competition. In March
1995, the CPUC announced it was postponing issuance of its proposed
policy statement to allow additional time for analysis of the extensive
record developed in connection with the order instituting a rulemaking
and an investigation (OIR/OII) on electric industry restructuring. The
CPUC was originally scheduled to propose a policy decision on March 22,
1995, with a final policy decision to be effective no earlier than
September 1995. Any proposed policy decision ultimately issued by the
CPUC will be subject to hearings and state legislative review before it
can be implemented.
In addition to responding to the OIR/OII (discussed further in Note 2
of Notes to Consolidated Financial Statements) and working closely with
the CPUC on the electric industry restructuring, the Company has made
several proposals to modify existing regulatory processes and to
provide additional pricing flexibility to those customers with the most
competitive options.
In an effort to allow large energy users to begin exercising choice
among electricity suppliers while public policy issues are resolved in
the OIR/OII, in February 1995, the Company requested CPUC approval to
implement as early as January 1996, an experimental "buy/sell" program.
Under the program, California utilities would offer certain retail
customers the option to receive electricity from competitive suppliers
through individually negotiated agreements under which the Company
would purchase electricity on behalf of the customer at prices
negotiated by the customer. However, the FERC recently issued a Notice
of Proposed Rulemaking (NOPR) on open access wholesale transmission
which indicated that programs like the one proposed by the Company
involved retail wheeling and cannot be implemented except under a
transmission tariff filed with the FERC. As a result, the Company is
reevaluating its experimental program.
On May 1, 1995, the Company filed open access wholesale electric
transmission tariffs for FERC jurisdictional customers. These tariffs
conform to the guidelines laid out in the NOPR on open access wholesale
transmission with very few modifications. The NOPR requires that all
utilities offer open access wholesale transmission service under
tariffs that are comparable to the wholesale transmission service that
utilities provide themselves. The Company's open access filing
proposes to enhance the existing wholesale market and is a step towards
the goal of promoting eventual competition in electric generation for
all customers. A final rule on the NOPR is not expected to be issued
before mid-1996.
The Company cannot predict the ultimate outcome of the ongoing changes
that are taking place in the utility industry. However, the Company
believes the end result will involve a fundamental change in the way it
conducts business. These changes may impact financial operating trends
and add volatility to the Company's earnings. The Company is actively
seeking regulatory and operational changes that will allow it to
provide energy services in a safe, reliable and competitive manner
while achieving strong financial performance.
Results of Operations
- ---------------------
The Company's results of operations for the three-month period ended
March 31, 1995 and 1994, are reflected in the following table and
discussed below.
Diablo
(in millions, except per share amounts) Utility Canyon Enterprises Total
1995
Operating revenues $ 1,776 $ 464 $ 67 $ 2,307
Operating expenses 1,475 286 81 1,842
------- ------ ------ -------
Operating income (loss) $ 301 $ 178 $ (14) $ 465
======= ====== ====== =======
Net income (loss) $ 192 $ 140 $ (3) $ 329
======= ====== ====== =======
Earnings (loss) per common share $ .42 $ .32 $ (.01) $ .73
======= ====== ====== =======
Total assets at March 31 $19,969 $5,989 $1,517 $27,475
======= ====== ====== =======
1994
Operating revenues $ 2,025 $ 435 $ 54 $ 2,514
Operating expenses 1,740 303 56 2,099
------- ------ ------ -------
Operating income (loss) $ 285 $ 132 $ (2) $ 415
======= ====== ====== =======
Net income $ 141 $ 96 $ - $ 237
======= ====== ====== =======
Earnings per common share $ .31 $ .21 $ - $ .52
======= ====== ====== =======
Total assets at March 31 $19,723 $6,195 $1,095 $27,013
======= ====== ====== =======
Earnings Per Common Share:
- -------------------------
Utility earnings per common share for the three-month period ended
March 31, 1995, were higher than for the comparable period of 1994,
reflecting charges in the first quarter of 1994 related to the CPUC
disallowances in the gas reasonableness proceedings for 1988 through
1990 and a reserve for other gas reasonableness matters, and a decrease
in other operating expenses in the first quarter of 1995. The Company
also recorded an increase in litigation reserves in the first quarter
of 1995 (See Note 6 of Notes to Consolidated Financial Statements).
Since the Diablo Canyon rate case settlement (Diablo Canyon settlement)
in 1988, Diablo Canyon has made an increasing contribution to the
Company's total earnings per common share. For the year ended December
31, 1994, Diablo Canyon contributed $1.04 (47 percent) to the total
earnings per common share of $2.21. The proposed modification of the
price for power produced by Diablo Canyon will likely cause a decrease
in the Diablo Canyon earnings per common share contribution. Earnings
from Diablo Canyon for the first quarter of 1995 were $0.06 per common
share less than what they otherwise would have been as a result of the
proposed price modifications to the Diablo Canyon settlement. Earnings
per common share for Diablo Canyon for the three-month period ended
March 31, 1995, increased as compared with the same period in 1994 due
to fewer scheduled refueling days in 1995, partially offset by the
impact of the proposed modification of the price for power produced by
Diablo Canyon.
Common Stock Dividend:
- ---------------------
In January 1995, the Board of Directors declared a quarterly dividend
of $.49 per common share which corresponds to an annualized dividend of
$1.96 per common share. 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. The Company has a long-term objective of reducing its
dividend payout ratio (dividends declared divided by earnings available
for common stock) to reflect the increased business risk in the utility
industry.
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.
Operating Revenues:
- ------------------
Electric revenues for the three-month period ended March 31, 1995,
decreased $120 million compared to the same period in 1994 primarily
due to a decrease in balancing account revenues resulting from the
decrease in electric energy costs caused by favorable hydro conditions
and lower natural gas prices. Offsetting this unfavorable variance
were favorable operating revenues from Diablo Canyon resulting from a
fewer number of scheduled refueling days offset by a decrease in the
price per kilowatthour (kWh) as provided in the proposed modified
pricing provisions of the Diablo Canyon settlement. As a result of the
favorable hydro conditions, it is possible the Company may curtail
Diablo Canyon operations pursuant to the Diablo Canyon settlement,
potentially decreasing second quarter revenues by as much as $75
million.
Gas revenues for the three-month period ended March 31, 1995, decreased
$100 million compared to the same period in 1994 primarily due to a
decrease in balancing account revenues resulting from a decline in the
volume and price of gas purchased.
Operating Expenses:
- ------------------
Operating expenses for the three-month period ended March 31, 1995,
decreased $257 million compared to the same period in 1994 primarily
due to the lower cost of electric energy and gas. The cost of electric
energy was $152 million less in 1995 primarily due to favorable hydro
conditions and lower natural gas prices. The cost of gas was $158
million less in 1995 primarily due to a decline in the volume and price
of gas purchased by the Company. Offsetting these operating expense
decreases was an increase in administrative and general expense
primarily due to an increase in litigation reserves.
Other Income and (Income Deductions):
- ------------------------------------
Other -- net for the three-month period ended March 31, 1994, included
accruals related to the CPUC gas reasonableness proceedings. There
were no charges recorded in the same period in 1995 related to gas
reasonableness proceedings. (See Note 3 of Notes to Consolidated
Financial Statements.)
Regulatory Matters:
- ------------------
In addition to the CPUC electric industry restructuring proposal and
the Company's response and related proposals (all discussed further in
Note 2 of Notes to Consolidated Financial Statements), the Company has
other ongoing regulatory matters with respect to revenues and costs
which will impact rates in 1995 and beyond. In numerous applications
related to electric rates, the Company has proposed to extend through
1996 its rate freeze which began in 1993. The freeze has been approved
by the CPUC through the end of 1995. Overall, the Company has
requested decreases in its gas rates compared to rates in effect for
1995. The more significant of these pending applications are discussed
below.
In its 1996 general rate case (GRC) application for base rates
effective January 1, 1996, the Company requests no change in electric
revenues and a $163 million decrease in gas revenues, compared to rates
in effect in 1995. In March 1995, the Division of Ratepayer Advocates
(DRA), a consumer advocacy branch of the CPUC, submitted its report on
the application, recommending a $434 million decrease in electric
revenues and a $292 million decrease in gas revenues. A significant
portion of the difference between the revenue change requested by the
Company and that recommended by the DRA relates to administrative and
general expenses and the level of wages and benefits. Hearings on the
1996 GRC began in April 1995, with a final decision on the application
expected in December 1995.
In March and April 1995, the Company filed a response to questions
raised by the GRC administrative law judge concerning customer service
issues. The reports detail the Company's actions to improve service
while reducing prices and respond to various questions, relating to
customer service and the Company's response to service interruptions
caused by severe storms in January and March of 1995. Hearings on
these issues began in April 1995 as part of the 1996 GRC. A CPUC
decision addressing issues related to the storm response is expected by
mid-1995.
In April 1995, the Company filed its energy cost application with the
CPUC which seeks to continue the Company's retail electric rate freeze
through the end of 1996. In order to maintain the freeze, the Company
proposed deferring the recovery of an estimated $85 million of the
electric balancing account undercollection beyond 1996. The Company
will forgo collection of interest on the deferred amount. As part of
the December 1994 decision on the Company's energy costs, the Company
agreed to defer recovery of $444 million of electric balancing account
undercollection and forgo recovery of interest on the deferral to 1996
and beyond. The reduction in the estimated amount that must be
deferred in order to maintain the rate freeze ($444 million from 1995
and $85 million from 1996), reflects the Company's belief that a
substantial portion of the undercollected energy cost balance will be
recovered during 1995 and 1996, due to the impacts of the proposed
Diablo Canyon price reduction on overall revenue requirements,
favorable hydro conditions and lower gas prices. If the CPUC does not
approve the proposed pricing modification to the Diablo Canyon
settlement, the estimated deferral beyond 1996 required to maintain the
rate freeze would increase from $85 million to approximately $590
million.
In April 1995, the Company's application with the CPUC requesting a gas
rate increase of approximately $170 million annually for the two-year
period beginning October 1, 1995, was updated and revised, lowering the
increase to $25 million. The Company's request reflects a decrease in
gas costs, an increase in transportation costs and the collection of
amounts previously deferred in balancing accounts. If the Company's
request is adopted, rates would be effective January 1, 1996,
concurrent with the implementation of the GRC.
In May 1995, the Company filed an application with the CPUC requesting
the following cost of capital for 1996:
Capital Weighted
Ratio Cost/Return Cost/Return
------- ----------- -----------
Common equity 48.00% 12.07% 5.79%
Long-term debt 46.50% 7.64% 3.55%
Preferred stock 5.50% 8.13% 0.45%
-----------
Total return on
average utility rate base 9.79%
=====
If approved, the Company's request would be effective January 1, 1996.
A final CPUC decision is expected in the fourth quarter of 1995.
In November 1993, the Company placed in service an expansion of its
natural gas transmission system from the Canadian border into
California. The pipeline provides additional firm capacity to the
Pacific Northwest and to Northern and Southern California. The total
cost of construction is approximately $1.7 billion. The Company has
filed applications with the FERC (for the interstate portion) and the
CPUC (for the portion within California) requesting that capital and
operating costs be found reasonable. Revenues are currently being
collected under rates approved by the FERC and the CPUC, subject to
refund. As part of the Company's cost of capital application, the
Company has requested a separate capital structure, a return on equity
of 13.00 percent and an overall rate of return of 9.41 percent for the
pipeline expansion. The Company expects final decisions in these
proceedings later in 1995 and 1996 and believes the final decisions on
these applications will not have a significant impact on its financial
position or results of operations.
Nonregulated Operations:
- -----------------------
The Company, through its wholly owned subsidiary, PG&E Enterprises
(Enterprises), has taken steps to position itself to compete in the
nonregulated energy business. Enterprises makes the majority of its
investments in nonregulated energy projects through a joint venture,
U.S. Generating Company, which invests, owns and operates plants in the
United States. Enterprises, in partnership with Bechtel Enterprises,
Inc., is in the process of forming a company to develop, build, own and
operate international electric generation projects.
In August 1994, Enterprises and Bechtel Enterprises, Inc. 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 80 percent.
In April 1995, the Company entered into an agreement to sell DALEN
Resources Corp. (DALEN), formerly PG&E Resources Company, as part of
the Company's goal to divest its interest in the oil and gas
exploration and production business. The sales price is $455 million,
including $340 million cash and assumption of $115 million of existing
debt. The sale is expected to close by June 1995 and result in a
minimal gain to the Company. The sales price is subject to certain
modifications as provided in the agreement.
Liquidity and Capital Resources
- -------------------------------
Sources of Capital:
- ------------------
The Company's capital requirements are funded from cash provided by
operations and, to the extent necessary, external financing. The
Company's policy is to finance its assets with a capital structure that
minimizes financing costs, maintains financial flexibility, and
complies with regulatory guidelines. This policy ensures that the
Company can raise capital to meet its utility obligation to serve and
its other investment objectives. During the three-month period ended
March 31, 1995, the Company issued $67 million of common stock through
its Dividend Reinvestment Program and Savings Fund Plan. The Company
purchased on the open market $110 million of common stock during the
three-month period ended March 31, 1995.
Risk Management:
- ---------------
The Company uses a number of techniques to mitigate its financial risk,
including the purchase of commercial insurance, the maintenance of
systems of internal control and the selected use of financial
instruments. The extent to which these techniques are used depends on
the risk of loss and the cost to employ such techniques. These
techniques do not eliminate financial risk to the Company.
The majority of the Company's financing is done on a fixed-term basis,
thereby eliminating the financial risk associated with variable
interest rate borrowings. The Company has used financial instruments
to eliminate the effects of fluctuations in interest rates and foreign
currency exchange rates on certain of its debt.
Investing and Financing Activity:
- --------------------------------
During the three-month period ended March 31, 1995, the Company's
capital expenditures were $197 million. This represents a $38 million
decrease from the same period in the preceding year.
The Company intends to redeem $68 million of mortgage bonds on June 1,
1995. The redemption of these bonds is expected to reduce the
Company's annual financing costs by approximately $1.2 million. The
estimated net present value savings are expected to total $11.4 million
over the life of the bonds.
In addition, Pacific Gas Transmission Company, a wholly owned
subsidiary of PG&E, filed a registration statement with the Securities
and Exchange Commission for the sale of up to $700 million of debt
securities and preferred stock in a shelf offering in which securities
are sold on a continuous or delayed basis in the future. Proceeds from
the offering will be used to refinance outstanding debt and for 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, the Company has an accrued liability at March
31, 1995, of $99 million for hazardous waste remediation costs. The
costs could be as much as $240 million, 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. (See Note 6 of Notes to Consolidated
Financial Statements.)
Legal Matters:
- -------------
In the normal course of business, the Company is named as a party in a
number of claims and lawsuits. In the past, substantially all of these
have been litigated or settled with no significant impact on either the
Company's results of operations or financial position.
There are several significant litigation cases which are discussed in
Note 6 of Notes to Consolidated Financial Statements. These cases
involve 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 Canadian natural gas purchases by one
of the Company's wholly owned subsidiaries and two claims that the
Company underpaid franchise fees.
Other Matters
- -------------
New Accounting Standard:
- -----------------------
The Financial Accounting Standards Board has issued Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of." The Company must adopt SFAS No. 121 by January 1, 1996,
but may elect to adopt it earlier.
The general provisions of SFAS No. 121 require, among other things,
that the existence of an impairment be evaluated whenever events or
changes in circumstances indicate that the carrying amount of an asset
may not be fully recoverable, and prescribe standards for the
recognition and measurement of impairment losses. In addition, SFAS
No. 121 requires that regulatory assets continue to be probable of
recovery in rates, rather than only at the time the regulatory asset is
recorded. Regulatory assets currently recorded may be written off if
recovery is no longer probable. The Company cannot predict the effect
the electric industry restructuring, discussed in Note 2, will have on
the recovery of its generation-related regulatory assets. Accordingly,
the Company cannot predict whether the adoption of this standard will
have a significant impact on its financial position or results of
operations.
Accounting for Decommissioning Expense:
- --------------------------------------
The staff of the Securities and Exchange Commission has questioned
current accounting practices of the electric utility industry,
regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating stations. In response to
these questions, the FASB has agreed to review the accounting for
removal costs, including decommissioning. If current electric utility
industry accounting practices for such decommissioning are changed: (1)
annual expense for decommissioning could increase and (2) the estimated
total cost for decommissioning could be recorded as a liability rather
than accrued over time as accumulated depreciation. The Company does
not believe that such changes, if required, would have an adverse
effect on its results of operations or liquidity due to its current
ability to recover decommissioning costs through rates.
PART II. OTHER INFORMATION
---------------------------
Item 4. Submission of Matters to a Vote of Security-Holders
---------------------------------------------------
On April 19, 1995, the Company held its regular annual meeting of
shareholders. At that meeting, the following matters were voted
as indicated:
1. Election of the following directors to serve until the
next annual meeting of shareholders or until their successors
shall be elected and qualified:
For Withheld
---------- -----------
Richard A. Clarke 346,918,671 11,081,400
Harry M. Conger 348,450,714 9,549,357
William S. Davila 348,505,402 9,494,669
David M. Lawrence, MD 346,784,403 11,215,668
Richard B. Madden 348,406,770 9,593,301
George A. Maneatis 345,722,379 12,277,692
Mary S. Metz 348,038,987 9,961,084
William F. Miller 348,336,349 9,663,722
Rebecca Q. Morgan 346,612,259 11,387,812
John B.M. Place 348,217,504 9,782,567
Samuel T. Reeves 348,628,593 9,371,478
Carl E. Reichardt 348,354,243 9,645,828
John C. Sawhill 348,309,815 9,690,256
Alan Seelenfreund 345,722,226 12,277,845
Stanley T. Skinner 346,988,141 11,011,930
Barry Lawson William 348,023,492 9,976,579
2. Ratification of the selection of Arthur Andersen LLP as
independent public accountants for the year 1995:
For: 350,465,400
Against: 3,498,531
Abstain: 4,036,140
Broker non-votes*: 0
3. Approval of aA shareholder proposal to limit each director's
total annual compensation to 2,000 shares of the Company's common
stock:
For: 38,843,094
Against: 247,430,336
Abstain: 14,286,952
Broker non-votes*: 57,439,689
- ----------------------------------
* A non-vote occurs when a nominee holding shares for a
beneficiary owner votes on one proposal, but does not vote on
another proposal because the nominee does not have discretionary
voting power and has not received instructions from the
beneficial owner.
Item 5. Other Information
-----------------
A. Open Access Tariffs for Wholesale Electric Transmission
On May 1, 1995, the Company filed with the Federal Energy
Regulatory Commission (FERC) two electric wholesale transmission
tariffs which the Company proposes be made available to all
eligible wholesale customers effective July 1, 1995. The two
tariffs filed by the Company, a Point-to-Point Transmission
Service tariff and a Network Integration Service Transmission
tariff, are based upon and are nearly identical to the pro-forma
tariffs proposed by the FERC in its
Notice of Proposed Rulemaking (NOPR) on open access wholesale
electric transmission.
In the NOPR, which was issued March 29, 1995, the FERC proposed
industry-wide open access for wholesale electric transmission
service and ancillary services. The NOPR sets out certain
minimum terms and conditions which the FERC expects utilities to
include in any tariffs which purport to provide this open access
wholesale transmission. The FERC also developed, and attached to
the NOPR, pro-forma tariffs which include these minimum terms and
conditions. Fundamentally, the NOPR requires that all utilities
offer open access to wholesale transmission service under tariffs
containing terms and conditions that make that wholesale
transmission service comparable to how the utilities usethe
wholesale transmission their systemsservice that utilities
provide themselves. The NOPR also makes clear that the FERC
intends that utilities be required to use these same tariffs in
making their own wholesale power transactions.
In the tariffs filed with the FERC on May 1, the Company made a
few clarifying changes to the pro-forma tariffs attached to the
NOPR, but otherwise adopted those tariffs completely. Taken
together, the two tariffs filed by the Company offer eligible
transmission customers wholesale transmission service comparable
to that which the Company provides itself.
As contemplated in the language of the NOPR, existing wholesale
transmission agreements the Company has with customers will not
be abrogated. Those wholesale customers will be permitted to
continue taking wholesale transmission service under their
existing agreements with the Company.
B. Management Changes
On April 19, 1995, the Company announced that Stanley T. Skinner,
currently president and chief executive officer (CEO) of the
Company, will become chairman of the board and CEO, effective
June 1, 1995. Richard A. Clarke, currently the chairman of the
board, will continue to serve as a director of the Company.
Robert D. Glynn Jr., currently executive vice president, will
become president and chief operating officer of the Company,
effective June 1, 1995. Mr. Glynn will be responsible for the
Company's utility operations including customer energy services,
electric supply, natural gas supply, nuclear power generation and
general services.
C. 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 three
months ended March 31, 1995 was 4.16. The Company's
earnings to combined fixed charges and preferred stock dividends
ratio for the three months ended March 31, 1995 was 3.67.
Statements setting forth the computation of the foregoing ratios
are filed herewith as Exhibits 12.1 and 12.2 to Registration
Statement Nos. 33-62488, 33-64136 and 33-50707.
Item 6. Exhibits and Reports on Form 8-K
---------------------------------
(a) Exhibits:
Exhibit 3 By-Laws as amended April 1, 1995
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 first quarter of 1995 and
through the date hereof:
1. January 4, 1995
Item 5. Other Events
A. Performance Incentive Plan - 1995 Target
B. California Public Utilities Commission
Proceedings
- 1995 Electric Rate Stabilization/Attrition
Rate Adjustment
- ECAC
- 1988 - 1990 Gas Reasonableness Proceedings
2. January 19, 1995
Item 5. Other Events
A. Performance Incentive Plan - 1994 Financial Results
B. 1994 Consolidated Earnings (unaudited)
C. Common Stock Dividend
D. California Public Utilities Commission Proceedings
- Core Procurement Incentive Mechanism
3. February 21, 1995
Item 5. Other Events
A. California Public Utilities Commission Proceedings
- Experimental Procurement Service for
Customer-Identified Electric Supply
4. March 2, 1995
Item 7. Financial Statements, Pro Forma Financial
Information and Exhibits
A. 1994 Financial Statements
B. Ratios of Earnings to Fixed Charges and Ratios of
Earnings to Combined Fixed Charges and Preferred
Stock Dividends
5. April 20, 1995
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. Electric Open Access NOPR
C. California Public Utilities Commission Proceedings
- Electric Fuel and Sales Balancing Accounts -
ECAC/ERAM
- Biennial Cost Allocation Proceeding (BCAP)
D. Sale of DALEN Resources Corp.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
PACIFIC GAS AND ELECTRIC COMPANY
May 12, 1995 THOMAS C. LONG
By______________________________
THOMAS C. LONG
Controller
EXHIBIT INDEX
Exhibit
Number Exhibit
- -------- --------------------------------------------------
Exhibit 3 By-Laws as amended April 1, 1995
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