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 June 30, 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 July 31, 1995
--------------- ------------------------------
Common Stock, $5 par value 424,390,650 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: Natural Gas Matters
Gas Reasonableness Proceedings.......... 11
Gas Accord Negotiations................. 12
Note 4: Diablo Canyon............................. 12
Note 5: Contingencies
Nuclear Insurance....................... 13
Environmental Remediation............... 13
Legal Matters........................... 14
Item 2. Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Competition and Changing Regulatory Environment.... 17
Results of Operations
Earnings Per Common Share........................ 20
Common Stock Dividend............................ 20
Operating Revenues............................... 21
Operating Expenses............................... 21
Other Income and (Income Deductions)............. 21
Regulatory Matters............................... 22
Nonregulated Operations.......................... 24
Liquidity and Capital Resources
Sources of Capital............................... 24
Risk Management.................................. 25
Investing and Financing Activity................. 25
Environmental Remediation........................ 25
Legal Matters.................................... 26
Other Matters
New Accounting Standard.......................... 26
Accounting for Decommissioning Expense........... 27
PART II. OTHER INFORMATION
---------------------------
Item 1. Legal Proceedings.................................... 28
Time-of-Use Meter Litigation/Customer
Notification Litigation.......................... 28
Norcen Litigation.................................. 29
Item 5. Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.............. 29
Item 6. Exhibits and Reports on Form 8-K..................... 30
SIGNATURE...................................................... 31
PART I. FINANCIAL INFORMATION
------------------------------
Item 1. Consolidated Financial Statements
---------------------------------
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(unaudited)
<CAPTION>
--------------------------------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
(in thousands, -------------------------- -------------------------
except per share amounts) 1995 1994 1995 1994
--------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric $1,894,108 $1,904,231 $3,590,352 $3,720,208
Gas 506,198 482,140 1,049,939 1,126,328
Other 47,424 53,309 114,790 107,415
---------- ---------- ---------- ----------
Total operating revenues 2,447,730 2,439,680 4,755,081 4,953,951
---------- ---------- ---------- ----------
OPERATING EXPENSES
Cost of electric energy 550,439 695,328 989,284 1,286,480
Cost of gas 83,349 73,378 186,912 334,764
Distribution 44,338 55,917 85,856 112,980
Transmission 58,720 64,354 125,475 137,046
Customer accounts and services 103,190 96,440 203,684 186,554
Maintenance 91,831 115,498 183,871 229,154
Depreciation and decommissioning 344,293 345,310 696,476 693,743
Administrative and general 214,592 267,819 475,713 462,988
Workforce reduction adjustment - - (18,195) -
Income taxes 304,649 210,883 570,147 460,593
Property and other taxes 76,103 75,424 149,972 156,239
Other 52,256 43,624 117,049 83,031
---------- ---------- ---------- ----------
Total operating expenses 1,923,760 2,043,975 3,766,244 4,143,572
---------- ---------- ---------- ----------
OPERATING INCOME 523,970 395,705 988,837 810,379
---------- ---------- ---------- ----------
OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 17,619 11,148 32,945 21,922
Allowance for equity funds
used during construction 6,462 5,058 12,100 9,737
Other--net 30,246 4,597 47,151 (3,766)
---------- ---------- ---------- ----------
Total other income and
(income deductions) 54,327 20,803 92,196 27,893
---------- ---------- ---------- ----------
INCOME BEFORE INTEREST EXPENSE 578,297 416,508 1,081,033 838,272
---------- ---------- ---------- ----------
INTEREST EXPENSE
Interest on long-term debt 162,423 167,468 324,572 323,192
Other interest charges 13,561 11,462 28,337 44,537
Allowance for borrowed funds
used during construction (3,207) (3,787) (6,083) (7,774)
---------- ---------- ---------- ----------
Net interest expense 172,777 175,143 346,826 359,955
---------- ---------- ---------- ----------
NET INCOME 405,520 241,365 734,207 478,317
Preferred dividend requirement 14,494 14,362 28,988 28,820
---------- ---------- ---------- ----------
EARNINGS AVAILABLE FOR
COMMON STOCK $ 391,026 $ 227,003 $ 705,219 $ 449,497
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING 426,621 429,762 428,344 429,150
EARNINGS PER COMMON SHARE $.92 $.53 $1.65 $1.05
DIVIDENDS DECLARED PER COMMON SHARE $.49 $.49 $ .98 $ .98
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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>
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June 30, December 31,
(in thousands) 1995 1994
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<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $17,260,836 $17,045,247
Diablo Canyon 6,669,054 6,647,162
Gas 7,609,391 7,447,879
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Total plant in service (at original cost) 31,539,281 31,140,288
Accumulated depreciation and decommissioning (12,942,814) (12,269,377)
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Net plant in service 18,596,467 18,870,911
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CONSTRUCTION WORK IN PROGRESS 510,060 527,867
OTHER NONCURRENT ASSETS
Oil and gas properties - 437,352
Nuclear decommissioning funds 697,561 616,637
Investment in nonregulated projects 782,136 761,355
Other assets 157,980 137,325
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Total other noncurrent assets 1,637,677 1,952,669
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CURRENT ASSETS
Cash and cash equivalents 416,277 136,900
Accounts receivable
Customers 1,252,579 1,413,185
Other 77,785 98,035
Allowance for uncollectible accounts (34,165) (29,769)
Regulatory balancing accounts receivable 1,105,479 1,345,669
Inventories
Materials and supplies 188,171 197,394
Gas stored underground 134,899 136,326
Fuel oil 46,619 67,707
Nuclear fuel 151,443 140,357
Prepayments 43,995 33,251
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Total current assets 3,383,082 3,539,055
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DEFERRED CHARGES
Income tax-related deferred charges 1,133,735 1,155,421
Diablo Canyon costs 392,095 401,110
Unamortized loss net of gain on reacquired debt 390,336 382,862
Workers' compensation and disability claims recoverable 247,065 247,209
Other 660,400 732,029
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Total deferred charges 2,823,631 2,918,631
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TOTAL ASSETS $26,950,917 $27,809,133
=========== ===========
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<FN>
(continued on next page)
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
--------------------------------------------------------------------------------------------
June 30, December 31,
(in thousands) 1995 1994
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<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,119,100 $ 2,151,213
Additional paid-in capital 3,789,881 3,806,508
Reinvested earnings 2,820,278 2,677,304
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Total common stock equity 8,729,259 8,635,025
Preferred stock without mandatory redemption provision 732,995 732,995
Preferred stock with mandatory redemption provision 137,500 137,500
Long-term debt 8,250,722 8,675,091
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Total capitalization 17,850,476 18,180,611
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OTHER NONCURRENT LIABILITIES
Customer advances for construction 149,018 152,384
Workers' compensation and disability claims 221,200 221,200
Other 784,460 644,233
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Total other noncurrent liabilities 1,154,678 1,017,817
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CURRENT LIABILITIES
Short-term borrowings 210,000 524,685
Long-term debt 416,939 477,047
Accounts payable
Trade creditors 321,140 414,291
Other 345,443 337,726
Accrued taxes 626,235 436,467
Deferred income taxes 311,674 432,026
Interest payable 78,915 84,805
Dividends payable 224,431 210,903
Other 427,630 643,779
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Total current liabilities 2,962,407 3,561,729
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DEFERRED CREDITS
Deferred income taxes 3,872,473 3,902,645
Deferred investment tax credits 382,443 391,455
Noncurrrent balancing account liabilities 173,222 226,844
Other 555,218 528,032
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Total deferred credits 4,983,356 5,048,976
CONTINGENCIES (Notes 2, 3 and 5) - -
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TOTAL CAPITALIZATION AND LIABILITIES $26,950,917 $27,809,133
=========== ===========
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS
(unaudited)
<CAPTION>
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Six months ended June 30,
-----------------------------
(in thousands) 1995 1994
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<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 734,207 $ 478,317
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and decommissioning 696,476 693,743
Amortization 69,189 54,691
Gain on sale of DALEN (13,107) -
Deferred income taxes and investment tax credits--net (134,184) 26,893
Allowance for equity funds used during construction (12,100) (9,737)
Other deferred charges 40,427 (14,770)
Other noncurrent liabilities 151,165 50,534
Noncurrent balancing account liabilities and
other deferred credits (26,436) 167,850
Net effect of changes in operating assets
and liabilities
Accounts receivable 185,252 (50,091)
Regulatory balancing accounts receivable 240,190 (166,513)
Inventories 31,738 13,861
Accounts payable (85,434) (54,588)
Accrued taxes 189,768 156,633
Other working capital (232,434) (36,849)
Other--net 33,851 13,876
---------- ----------
Net cash provided by operating activities 1,868,568 1,323,850
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CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures (399,033) (458,909)
Allowance for borrowed funds used during construction (6,083) (7,774)
Nonregulated expenditures (59,767) (163,968)
Proceeds from sale of DALEN 340,000 -
Other--net (78,053) 16,931
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Net cash used by investing activities (202,936) (613,720)
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CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 92,315 138,768
Common stock repurchased (267,799) (60,320)
Preferred stock issued - 62,312
Preferred stock redeemed - (82,995)
Long-term debt issued 567,160 55,000
Long-term debt matured or reacquired (957,583) (230,245)
Short-term debt--net (314,685) (129,151)
Dividends paid (451,082) (441,277)
Other--net (54,581) 15,380
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Net cash used by financing activities (1,386,255) (672,528)
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NET CHANGE IN CASH AND CASH EQUIVALENTS 279,377 37,602
CASH AND CASH EQUIVALENTS AT JANUARY 1 136,900 61,066
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CASH AND CASH EQUIVALENTS AT JUNE 30 $ 416,277 $ 98,668
========== ==========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 330,640 $ 338,144
Income taxes 459,028 232,519
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
NOTE 1: GENERAL
----------------
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 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 1994, the Company accrued $249 million in connection with its 1994-
1995 workforce reduction program consisting of both a voluntary
retirement incentive and severances. The majority of the severances
are in generation and transmission functions.
In April 1995, the Company canceled approximately 800 of the 3,000
planned 1994-1995 reductions in order to accelerate maintenance on its
system in light of the severity of the damage caused by storms in the
winter of 1995 and the identification of certain facilities that would
benefit from a more extensive and accelerated maintenance program. As
a result, the estimated severance costs accrued and expensed in 1994
were reduced by $18.2 million in March 1995.
At June 30, 1995, a severance reserve of approximately $17.7 million
remained. Charges against the reserve will be made for the
approximately 100 severances remaining to be accomplished and the
remaining payments to previously severed employees when paid.
The Company will not seek rate recovery for the cost of the 1994-1995
workforce reductions.
NOTE 2: Electric Industry Restructuring
----------------------------------------
In May 1995, the California Public Utilities Commission (CPUC) released
two proposed policy decisions, both the result of testimony, hearings
and comments on its order instituting rulemaking and investigation
(OIR/OII) on electric industry restructuring issued in April 1994. The
proposals request comments on and set schedules to restructure the
California electric utility industry. Three commissioners supported a
policy decision which would require the establishment of a wholesale
pool for power. All utility generators would be required to sell power
into the pool and distribution companies on behalf of their customers
would, with few exceptions, purchase all of their electric generation
needs from the pool. This proposal, which would go into effect in
1997, contemplates a possible transition to direct access beginning as
early as 1999 if certain implementation issues are resolved. The CPUC
would use performance-based ratemaking (PBR) for any service not
subject to competition. One commissioner offered an alternative policy
decision which proposes immediate conversion to direct access in 1998.
Under this proposal, all consumers would have the option to enter
directly into individual agreements for the purchase of power from
power producers.
Both proposals provide utilities reasonable assurance that they will
recover substantially all past investments and commitments made in
reliance on the traditional utility regulatory compact. Uneconomic
assets and obligations (costs which are above market and could not be
recovered under market-based pricing) are to be recovered through a
competition transition charge (CTC). Neither proposal indicates
precisely how the CTC is to be recovered.
Majority Proposal: Under the majority proposal, the Company, Southern
California Edison Company and San Diego Gas and Electric Company would
seek approval from the Federal Energy Regulatory Commission (FERC) to
establish an independent system operator, who would be responsible for
transmission scheduling and economic dispatch of generation.
Participants in the pool would transfer operating control, but not
ownership, of their transmission assets to that operator. All other
power suppliers including municipal utilities, power marketing
agencies, independent power producers and out-of-state generators would
be invited to participate through sales or purchases to and from the
pool and would be given nondiscriminatory access to transmission
services.
Under the wholesale pool concept, the price of electricity provided by
the generators is determined by an auction conducted by the independent
system operator in real time and revealed to the market each day.
Under real time pricing, the price of electricity provided by the
generators is set hourly or at some other time interval as determined
by the independent system operator, reflecting changes in the cost of
generation. Customers would be given the choice of a rate scheme which
reflects real time pricing of generation or one which averages the cost
of electricity by monthly consumption. Customers could also choose to
lock in energy prices through financial contracts, referred to as
contracts for differences. Real time price meters would be phased in
for all customers who want them by 2003. Customers would be
individually responsible for the cost of the meter.
The majority proposal would require the disaggregation of generation,
transmission and distribution functions. In order to address possible
market domination, the CPUC intends to consider the impacts of
structural separation and whether divestiture of a portion or all of
utility nonnuclear and nonhydro generation assets to independent
generation firms is required. The proposal also intends to address
potential remedies for abuses resulting from market domination.
Under the majority proposal, investor-owned utilities would retain
ownership of their existing nuclear and hydro facilities. The CPUC
hopes that the average bundled rate of nuclear and hydro facilities
would be competitive with the prices expected to result from the pool,
thereby minimizing or eliminating the need for further CTC recovery for
these resources. However, based on the current pricing of the
Company's hydro facilities and the Company's Diablo Canyon Nuclear
Power Plant (Diablo Canyon), the Company expects that although
significantly reduced, there may still be a need for CTC recovery for
Diablo Canyon.
The majority proposal would leave intact the Diablo Canyon rate case
settlement (Diablo Settlement) and contracts with existing qualifying
facilities (QFs).
The majority proposal notes that other utility generating assets should
also be able to compete without CTC recovery. Nonetheless, some CTC
recovery would still be provided for nonnuclear, nonhydro plants which
a utility retained. The CTC for these plants is defined as the
difference between book and market value. Market value for retained
plants would be determined administratively using a combination of a
forecast of market prices for power with an annual true-up to pool
prices. For these retained plants, the return on rate base would be
limited by a floor and ceiling of 150 basis points below or above the
utility's allowable overall return on rate base. Revenues collected in
excess of the ceiling would be used to reduce the CTC.
If a utility divests itself of its generating assets, the CTC would be
calculated by netting the total price received with the total book
value for the plants divested.
All existing QF contracts would continue to be honored by the remaining
electric distribution utility. However, the QF contract costs would be
passed along to customers by imputing only the pool price as the price
for QF power, with the remaining portion of the QF contract price
collected as part of the CTC.
As an incentive for QF buyouts, the utility would be allowed to keep 20
percent of any savings from renegotiated QF contract capacity payments.
In addition, the CPUC eventually intends to revise the "avoided cost"
calculation for QF energy payments in a manner based on the pool price.
Finally, the CPUC proposes to allocate 50 percent of future benefits
associated with declining QF contract expenses to finance the
acceleration of CTC recovery for uneconomic QF contracts.
The majority proposal indicates that regulatory assets which are
specifically attributable to utility generation should get full CTC
protection. The CPUC has asked for comments on which specific
regulatory assets should be allowed as transition costs.
The time period for collection of the CTC is not specified in the
majority proposal, but would be consistent with the current level of
rates, while also allowing ratepayers the opportunity to reap the
benefits of lower generation costs from the pool.
Alternative Proposal: The alternative policy decision proposes to
streamline regulation and grant consumer choice through direct access
by relying on direct purchase/sales arrangements between buyers and
sellers of electricity. This proposal seeks to allow direct access for
all customers commencing January 1, 1998.
Consistent with the majority proposal, the alternative proposal would
separate generation assets from transmission, distribution and other
assets. This could occur through either a sale of assets or spin-off
of generation facilities to shareholders, leaving the utility owning
only transmission and distribution facilities (i.e., an Electric
Distribution Company, or EDC). A neutral operating company would also
be established for generation dispatch and transmission operation to
ensure reliability of the grid.
Similar to the majority proposal, under the alternative proposal, the
EDC would be regulated under a PBR approach. In addition, the EDC
would be obligated to procure electric supplies for those customers who
choose to remain with the utility.
Transition costs would be levied as a monthly charge on all customers,
whether they are utility or direct access customers. The CTC would be
recovered over a period of time to ensure that rates do not rise above
current levels. Three types of transition costs are identified in the
alternative proposal: utility generation assets, QF contracts and
regulatory balancing accounts.
For utility generating assets, the CTC would be 90 percent of the
difference between aggregate book value and aggregate sale price (or
stock price in the event of a spin-off). Diablo Canyon would be sold
or spun off, but the EDC would retain the obligation to purchase Diablo
Canyon power at settlement prices through January 2008. After January
2008, Diablo Canyon would compete on price. The CTC for Diablo Canyon
would be computed in the same manner as for QF contracts, but Diablo
Canyon would be exempt from the 90/10 split applicable to other utility
generating assets provided the revised Diablo Canyon Settlement prices
approved by the CPUC in May 1995, represent a rate reduction
"commensurate" with the 90/10 split.
Under the alternative proposal, the EDC would retain the obligation to
purchase QF power under QF contracts and would receive full recovery of
all QF costs, including the uneconomic portion which would be part of
the CTC. However, utilities would be allowed to retain 50 percent of
any demonstrable savings resulting from renegotiated QF contracts.
The alternative proposal also allows full recovery of outstanding
regulatory asset balances other than nuclear decommissioning costs,
subject to CPUC approval of specific accounts in the implementation
phase. For nuclear decommissioning costs, two options are proposed:
ultimate sale of the plants with the new owner taking responsibility
for decommissioning, or including the continued trust fund requirements
in the CTC.
Company Response: In July 1995, the Company filed its response on the
CPUC proposals for restructuring the electric industry. In its
response, the Company reaffirmed its commitment to achieving direct
access. However, if a wholesale pool under the majority proposal
remains the preferred approach by the CPUC, the Company indicated that
it is prepared to work towards a pool structure keeping the direct
access vision in mind. Although it supports the direct access concept
in the alternative proposal, the Company believes that the plan to
simultaneously implement that structure for all customers raises
significant technological and practical obstacles. In addition, the
Company does not support the alternative proposal's requirement for
immediate and complete divestiture of utility generating assets or the
mandated shareholder absorption of 10 percent of the transition costs.
Under the majority proposal, the Company concluded that the transition
cost mechanism is acceptable in concept, although the mechanics of its
application to fossil generation assets needs further attention, and
more particularly, better integration with PBR concepts.
The Company also strongly supports the majority proposal's procedure to
periodically recalibrate transition costs. Under this procedure,
reestimation of the CTC would occur yearly and would be reconciled and
tracked using a balancing account procedure which would ensure that
neither ratepayers nor the utility assume a disproportionate risk of
CTC forecast error. The Company also indicated that the appropriate
carrying cost for any outstanding generating asset CTC should be the
authorized rate of return for the utility.
In its comments, the Company noted that apart from whether a CPUC
ordered divestiture of generation assets as mandated under the
alternative proposal can legally be required, the actual process of
divesting, either through auction or spin-off, is itself an immensely
complex, lengthy and costly undertaking. It is unlikely that this
could be managed between now and when direct access is proposed to
commence. In addition, the divestiture approach will likely increase
CTC costs.
The CPUC has scheduled full panel hearings in August and September 1995
to assist in development of its final policy decision. The CPUC
indicated that it will work with the California State Legislature
(Legislature), the Governor, other western jurisdictions and the FERC
to facilitate restructuring of the California electric industry. The
Company intends to participate in all these proceedings.
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 June 30, 1995.
If either proposal 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 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
$513 million which are expected to be recovered in the near term, were
approximately $1.5 billion at June 30, 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 its ability to recover
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 net book value of the
Company's generation assets, excluding Diablo Canyon, was approximately
$2.7 billion at June 30, 1995. The net book value of the Company's
investment in Diablo Canyon was approximately $5.0 billion at June 30,
1995.
Based on the nature of the CTC recovery for uneconomic generation
assets, obligations related to QF facilities and generation-related
regulatory assets proposed in the majority and alternative proposals,
the Company currently does not anticipate a material impairment due to
the impending electric industry restructuring. However, should the
CPUC or the Legislature modify these proposals, an impairment loss
could ultimately occur.
Currently, the Company is unable to predict the final 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: Natural Gas Matters
----------------------------
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 disallowances recommended by the DRA 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 had 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 unresolved 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.
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
described above. The Company believes the ultimate outcome of these
matters will not have a significant impact on its financial position or
results of operations.
Gas Accord Negotiations:
-----------------------
In July 1995, a CPUC Administration Law Judge approved a request by the
Company to suspend hearings on the market impacts of the PG&E portion
of the PGT/PG&E Pipeline Expansion Project. The Company sought
suspension of such hearings to enable parties to engage in meaningful
settlement negotiations encompassing both a restructuring of PG&E's gas
transmission operations and a broad range of gas related issues arising
from various proceedings. All other individual gas proceedings are
continuing while the gas accord negotiations are being conducted.
Specific issues to be covered by the proposed gas accord will be
determined as negotiations continue.
Negotiations are expected to begin in August or September 1995. In
November 1995, a proposed gas accord or a status report will be
submitted to the CPUC.
The Company believes the ultimate outcome of the gas accord
negotiations will not have a significant impact on its financial
position or results of operation.
NOTE 4: Diablo Canyon
----------------------
On May 24, 1995, the CPUC issued its decision approving an agreement
providing for a modification to the pricing provisions of the Diablo
Settlement. The agreement was executed in December 1994 by the
Company, the DRA, the California Attorney General and several other
parties representing energy consumers.
Under the modification approved by the CPUC, the price for power
produced by Diablo Canyon is reduced from the level set in the Diablo
Settlement as originally adopted in 1988; all other terms and
conditions of the Diablo Settlement remain unchanged. The new prices
are shown in the table below. Based on Diablo Canyon's current
operating performance, the modification will result in approximately
$2.1 billion less revenue through 1999, compared to the original
pricing provisions of the Diablo Settlement.
Diablo Canyon Price (cents) per kilowatt-hour
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
Original Settlement Agreement Price* 12.15 12.42 12.70 12.98 13.28
Modified Price 11.00 10.50 10.00 9.50 9.00
--------------
* Assumes 3.5% inflation
After December 31, 1999, the escalating portion of the Diablo Canyon
price will increase using the same formula specified in the Diablo
Settlement. The modification provides the Company with the right to
reduce the price below the amount specified if it so chooses.
The CPUC decision approving the modification adopts the parties'
proposal that the difference between the Company's revenue requirement
under the original Diablo Settlement prices and the proposed prices be
applied to the Company's energy cost balancing account until the
undercollection in that account as of December 31, 1995, is fully
amortized.
NOTE 5: 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 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 cost 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 June 30, 1995, of $100 million
for hazardous waste remediation costs. The costs may be as much as
$245 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 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 June 30, 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.
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 106
other cities with which the Company has certain electric franchise
contracts. The complaint alleges that, since at least 1987, 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
Company has filed a motion for summary judgment in this case and a
motion to decertify the class. The case is 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 $27 million as of June 30,
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 services 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 a restructured utility industry. However, there have been delays in
instituting the regulatory reforms necessary to open markets to
competition.
In May 1995, following more than one year of testimony, comments and
hearings on the CPUC's order instituting rulemaking and investigation
on the restructuring of the California electric utility industry, the
CPUC issued two proposed policy decisions. The proposal by the
majority of the commissioners supports the concept of a wholesale power
pool. This proposal, which would go into effect in 1997, contemplates
a possible transition to direct access beginning no earlier than 1999
if certain implementation issues are resolved. Under this proposal,
all generators would be required to sell power generated into the pool
and distribution companies, on behalf of their customers would, with
few exceptions, purchase all of their electric generation needs from
the pool. Under the wholesale pool proposal, performance-based
ratemaking would be used for any services not subject to competition.
One commissioner offered an alternative proposal which supports
immediate conversion to direct access for all customers beginning in
1998. Both proposals call for the separation of generation,
transmission and distribution functions and the possibility of
mandatory divestiture of generation assets. The proposals also support
transition cost recovery of uneconomic assets and obligations (i.e.,
costs which are above market and could not be recovered under market-
based pricing) through a competition transition charge (CTC).
In July 1995, the Company filed its response on the CPUC proposals for
restructuring the electric industry. In its response, the Company
reaffirmed its commitment to achieving direct access. However, if a
wholesale pool as contemplated under the majority proposal remains the
preferred approach by the CPUC, the Company indicated that it is
prepared to work towards a pool structure keeping the direct access
vision in mind. Under either proposal, the Company believes that
significant technological, regulatory (state and federal) and practical
obstacles will have to be overcome. In addition, the Company does not
support immediate and complete divestiture of utility generating assets
or the mandated shareholder absorption of a portion of transition costs
associated with generating plants. The Company does believe that the
transition recovery for qualifying facilities and regulatory assets is
equitable.
The proposed policy decisions are subject to hearings and state
legislative review before either could be implemented. (See Note 2 of
Notes to Consolidated Financial Statements for further discussion.)
In addition to 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 June 1995, the FERC accepted, subject to refund and the outcome of
the FERC Notice of Proposed Rulemaking (NOPR) on open access, the
Company's proposed open access wholesale electric transmission tariffs,
effective July 1, 1995. These tariffs conform to the guidelines laid
out in the FERC 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.
In August 1995, the Company filed comments with the FERC on the NOPR.
In its comments, the Company indicated that it strongly supports the
direction of the FERC reflected in the NOPR. The Company also believes
that it is essential that the FERC afford the utilities the opportunity
to propose in the future new innovative transmission models that would
respond more efficiently to changing market demands once open access is
widespread. This flexibility will become increasingly important as the
volume of transactions on the system increases and retail wheeling
emerges as an option for customers.
The Company supports the FERC's recognition that full transition cost
recovery is appropriate, that the states have the primary role in
determining and levying transition cost surcharges for retail
customers, and that transition cost recovery at the FERC is appropriate
for former retail customers which municipalize or in other ways become
wholesale entities. The Company also encourages the FERC to clarify
that its jurisdictional demarcation between transmission and
distribution facilities cannot be circumvented by retail customers
attempting to evade state transition cost charges. A final rule on the
NOPR is not expected to be issued before mid-1996.
The Company is also actively pursuing changes in its gas business. In
July 1995, the Company proposed that parties in pending gas proceedings
before the CPUC (See Regulatory Matters) negotiate a wide-ranging
settlement of such proceedings as part of a restructuring of its gas
transmission business.
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 make the Company's earnings more volatile. 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 and six-month
periods ended June 30, 1995, and 1994, are reflected in the following
table:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
JUNE 30
Diablo
(in millions, except per share amounts) Utility Canyon Enterprises Total
<S> <C> <C> <C> <C>
1995
Operating revenues $ 1,856 $ 545 $ 47 $ 2,448
Operating expenses 1,540 323 61 1,924
------- ------ ------ -------
Operating income (loss) $ 316 $ 222 $ (14) $ 524
======= ====== ====== =======
Net income $ 213 $ 183 $ 10 $ 406
======= ====== ====== =======
Earnings per common share $ .48 $ .42 $ .02 $ .92
======= ====== ====== =======
1994
Operating revenues $ 1,989 $ 398 $ 53 $ 2,440
Operating expenses 1,709 279 56 2,044
------- ------ ------ -------
Operating income (loss) $ 280 $ 119 $ (3) $ 396
======= ====== ====== =======
Net income (loss) $ 174 $ 80 $ (13) $ 241
======= ====== ====== =======
Earnings (loss) per common share $ .38 $ .18 $ (.03) $ .53
======= ====== ====== =======
SIX MONTHS ENDED
JUNE 30
Diablo
(in millions, except per share amounts) Utility Canyon Enterprises Total
1995
Operating revenues $ 3,631 $1,009 $ 115 $ 4,755
Operating expenses 3,015 609 142 3,766
------- ------ ------ -------
Operating income (loss) $ 616 $ 400 $ (27) $ 989
======= ====== ====== =======
Net income $ 405 $ 322 $ 7 $ 734
======= ====== ====== =======
Earnings per common share $ .89 $ .74 $ .02 $ 1.65
======= ====== ====== =======
Total assets at June 30 $19,696 $5,854 $1,401 $26,951
======= ====== ====== =======
1994
Operating revenues $ 4,014 $ 833 $ 107 $ 4,954
Operating expenses 3,450 582 112 4,144
------- ------ ------ -------
Operating income (loss) $ 564 $ 251 $ (5) $ 810
======= ====== ====== =======
Net income (loss) $ 315 $ 176 $ (13) $ 478
======= ====== ====== =======
Earnings (loss) per common share $ .69 $ .39 $ (.03) $ 1.05
======= ====== ====== =======
Total assets at June 30 $19,926 $6,131 $1,165 $27,222
======= ====== ====== =======
</TABLE>
Earnings Per Common Share:
-------------------------
The Company earnings per common share for both the three-month and six-
month periods ended June 1995, were greater than for the same periods
in the previous year. As discussed below, each of the Company's
operations reported higher earnings per common share in 1995.
Utility earnings per common share for the three-month period ended June
30, 1995, were higher than for the comparable period in 1994,
reflecting a charge in 1994 for litigation reserves. Utility earnings
per common share for the six-month period ended June 30, 1995, were
higher than for the comparable period in 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 matters.
Earnings per common share for Diablo Canyon for the three-month and
six-month periods ended June 30, 1995, increased as compared with the
same periods in 1994 due to fewer scheduled refueling days and
unscheduled outages in 1995, partially offset by the impact of the
modified price for power produced by Diablo Canyon. The next refueling
is scheduled to begin September 30, 1995 (Unit 1).
In June 1995, Enterprises completed its sale of DALEN Resources Corp.
(DALEN). The transaction resulted in an after tax gain of $.03 per
common share. (See Nonregulated Operations section for further
discussion.) In June 1994, Enterprises entered into multiple contracts
to sell certain of its oil and gas properties. As a result, the
Company's earnings per common share for the three-month and six-month
periods ended June 30, 1994, included a writedown of $.03 per common
share for certain oil and gas properties held for sale.
Common Stock Dividend:
---------------------
In May 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 six-month period ending June 30, 1995,
decreased $130 million, compared to the same period in 1994, primarily
due to a decrease in balancing account revenues resulting from lower
electric energy costs caused by favorable hydro conditions and lower
natural gas prices. This decrease was offset by favorable operating
revenues from Diablo Canyon resulting from fewer scheduled refueling
days and unscheduled outages in 1995. These results were partially
offset by a decrease in the price per kilowatt-hour (kWh) as provided
in the modified pricing provisions of the Diablo Canyon rate case
settlement (Diablo Canyon Settlement). Based on Diablo Canyon's
current operating performance, the modification will result in
approximately $2.1 billion less revenue through 1999, compared to the
original pricing provisions of the Diablo Canyon Settlement. After
December 31, 1999, the escalating portion of the Diablo Canyon price
will increase using the same formula specified in the Diablo Canyon
Settlement. (See Note 4 of Notes to Consolidated Financial
Statements.)
Gas revenues for the six-month period ended June 30, 1995, decreased
$76 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 and six-month periods ended June
30, 1995, decreased $120 million and $377 million, respectively,
compared to the same periods in 1994, primarily due to the lower cost
of electric energy. The cost of electric energy was $145 million and
$297 million less in the three-month and six-month periods ended June
30, 1995, respectively, compared to the same periods in 1994. The
reduction in costs was primarily due to favorable hydro conditions.
Most of the cost of gas decrease of $148 million in the six-month
period ended June 30, 1995, compared to the same period in 1994, was
due to higher prices paid during the first three months of 1994.
Administrative and general expense was $53 million less in the three-
month period ended June 30, 1995, compared to the same period in 1994,
primarily due to an increase in litigation reserves recorded in 1994.
Partially offsetting these operating expense decreases was an increase
in income tax expense. Income tax expense increased as a result of
higher income in 1995.
Other Income and (Income Deductions):
------------------------------------
Other -- net for the six-month period ended June 30, 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
(discussed further in Note 2 of Notes to Consolidated Financial
Statements) and related proposals, there are other ongoing regulatory
matters with respect to revenues and costs which will impact the
Company's rates in 1995 and beyond. In 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.
Hearings in the revenue requirements phase of the Company's 1996
General Rate Case (GRC) application for base rates effective January 1,
1996, were completed in June 1995. As a result of updated information,
the Company has revised its request and is currently seeking an $87
million decrease in electric revenues and a $191 million decrease in
gas revenues, compared to 1995 rates. During the hearing process, the
Division of Ratepayer Advocates (DRA), a consumer advocacy branch of
the CPUC, revised its position to recommend a $331 million decrease in
electric revenues and a $291 million decrease in gas revenues, compared
to 1995 rates. 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. Other intervenors have made proposals to lower electric
revenues by approximately $100 million and gas revenues by
approximately $40 million, above the DRA recommendations. A final
decision on the revenue requirements phase of the application is
expected in December 1995. The Company believes that 1996 revenues
ultimately adopted by the CPUC may be significantly less than that
requested by the Company and to the extent the Company is unable to
identify additional cost reductions to offset revenue reductions,
earnings in 1996 would decrease.
In June 1995, the Company updated its April 1995 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.
Based on the consolidation of the outstanding electric cases that would
become effective January 1, 1996, including the energy cost and the GRC
proceedings, it is currently expected that the deferral of the electric
balancing account undercollection will not be required.
In August 1995, the DRA updated its report in the Company's 1996 energy
cost proceeding recommending a reduction of approximately $62 million
in the energy cost revenue requirement requested by the Company in the
Energy Cost proceedings primarily due to lower gas cost and purchased
power expenses.
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 will 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 will not result in a rate increase.
In July 1995, the DRA filed its 1996 cost of capital proposal
recommending for the Company (excluding PG&E's portion of the PGT/PG&E
Pipeline Expansion Project) a return on common equity of 11.15 percent
and an overall return on utility rate base of 9.35 percent. The DRA
recommended a utility capital structure that was consistent with that
proposed by the Company. The DRA's proposal would result in annual
revenue requirement decreases of $72 million for electric rates and $23
million for gas rates 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 PGT/PG&E Pipeline Expansion Project (Pipeline
Expansion) provides additional firm transportation capacity to Northern
and Southern California and the Pacific Northwest. The total cost of
construction was approximately $1.7 billion. The Company has filed
applications with the FERC (for the Pacific Gas Transmission Company
(PGT) or interstate portion) and the CPUC (for the PG&E or California
portion) 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 adjustment. 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 PG&E portion of the
Pipeline Expansion (the PG&E Pipeline Expansion). The DRA has
recommended that the Company be allowed a return on equity of 12.15
percent and an overall rate of return of 9.13 percent on the PG&E
Pipeline Expansion.
In June 1995, a CPUC administrative law judge (ALJ) issued an order
setting hearings to consider the market impacts of the PG&E Pipeline
Expansion. The ALJ's order also re-opened the proceeding in which the
CPUC had approved the PG&E Pipeline Expansion, in order to consider
alleged discovery violations committed by the Company in that
proceeding.
In July 1995, the ALJ approved a request by the Company to suspend on
the market impacts hearings in the PG&E Pipeline Expansion proceeding.
The Company sought a suspension of such hearings to enable parties to
engage in meaningful settlement negotiations encompassing both a
restructuring of PG&E's gas transmission operations and a broad range
of gas-related issues arising from various proceedings. (See Note 3 of
Notes to Consolidated Financial Statements for further discussion.)
Settlement negotiations are expected to begin in August or September
1995. Any gas accord proposal arising from such negotiations would be
subject to CPUC approval. The Company believes the ultimate outcome of
the gas accord negotiations will not have a significant impact on its
financial position or results of operations.
Nonregulated Operations:
-----------------------
The Company, through its wholly owned subsidiary, 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., has formed
a company named International Generating Co., Ltd. (InterGen) to
develop, build, own and operate international electric generation
projects.
In August 1994, Enterprises and Bechtel Enterprises, Inc., completed
the 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 90
percent.
In June 1995, the Company completed its sale of DALEN. The sales price
was $455 million, including $340 million cash and assumption of $115
million of existing debt. The sale resulted in an after tax gain of
approximately $13 million.
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 six-month period ended
June 30, 1995, the Company issued $92 million of common stock,
primarily through its Dividend Reinvestment Program and Savings Fund
Plan. The Company purchased on the open market $268 million of common
stock during the six-month period ended June 30, 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 substantially reducing 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 six-month period ended June 30, 1995, the Company's capital
expenditures were $399 million. This represents a $60 million decrease
from the same period in the preceding year.
During the six-month period ended June 30, 1995, the Company redeemed
or repurchased approximately $114 million of mortgage bonds. Also, the
Company plans to redeem $150 million of perpetual, redeemable preferred
stock on September 1, 1995.
During the six-month period ended June 30, 1995, PGT, a wholly owned
subsidiary of PG&E, completed the sale of $400 million of debt
securities through a shelf offering filed with the Securities and
Exchange Commission. Additionally, PGT issued commercial paper, $170
million of which was outstanding at June 30, 1995. The commercial
paper is supported by a five-year $200 million bank revolving credit
agreement. The commercial paper outstanding at June 30, 1995, is
classified as long-term since PGT intends to renew or replace it with
long-term borrowings. Substantially all of the proceeds from the debt
offering and sale of commercial paper were used to refinance
outstanding debt of PGT.
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 cost 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 June 30, 1995, of
$100 million for hazardous waste remediation costs. The costs could be
as much as $245 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 5 of Notes to Consolidated Financial
Statements.)
Legal Matters:
-------------
In the normal course of business, the Company is named as a party in a
number of claims and lawsuits. Substantially all of these have been
litigated or settled with no significant impact on either the Company's
results of operations or financial position.
There are three significant litigation cases which are discussed in
Note 5 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 a claim that the Company
underpaid franchise fees.
Other Matters
-------------
New Accounting Standard:
-----------------------
The Financial Accounting Standards Board (FASB) 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.
Based on the nature of CTC recovery for generation-related regulatory
assets proposed in the majority and alternative electric industry
restructuring proposals discussed in Note 2 of Notes to Consolidated
Financial Statements, the Company currently does not anticipate a
material impairment of its regulatory assets due to the impending
electric industry restructuring.
However, should the CPUC or the California State Legislature modify
these proposals, an impairment loss related to regulatory assets
attributable to electric generation and other investments in utility
generation assets could ultimately result.
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 1. Legal Proceedings
-----------------
A. Time-Of-Use Meter/Customer Notification Litigation
As previously reported in the Company's Form 10-K for the fiscal year
ended December 31, 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 alleged class was later broadened to include customers of
the Turlock Irrigation District (TID), which purchases power from the
Company. The complaint alleged 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 sought damages estimated to be in excess of $16
billion.
In April 1995, the Court granted portions of the Company's demurrer
in this case, holding that two of the individual plaintiffs did not
have standing to sue. The claims relating to those individuals and
the customers of TID have been dropped.
On June 8, 1995, the three remaining plaintiffs filed an amended
complaint which alleges that (a) under certain circumstances the
Company has a duty to notify a particular customer of the most
favorable rate for that customer and (b) the Company has
systematically failed to reasonably advise new and existing customers
of available advantageous rate structures, including the time-of-use
billing option. The amended complaint estimates class wide damages
related to time-of-use rates to be in excess of $16 billion and that
the damages relating to other programs and rate structures is at
least an additional $10 billion. The amended complaint also seeks
$100 billion in exemplary damages relating to the Company's alleged
willful failure to provide required notice to customers of rate
options.
On July 11, 1995, the Company filed (i) a motion to strike the class
and leave only the claims of the three individual plaintiffs, (ii) a
motion for summary judgment against one of the three plaintiffs and
(iii) a demurrer asserting that the California Public Utilities
Commission (CPUC) has exclusive jurisdiction and that the Superior
Court should dismiss the entire action. These motions are scheduled
to be heard later in 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.
B. Norcen Litigation
As previously reported in the Company's Annual Report on Form 10-K
for the fiscal year ended December 31, 1994, in March 1994, Norcen
Energy Resources Limited (Norcen Energy) and Norcen Marketing
Incorporated (Norcen Marketing) filed a complaint in the U.S.
District Court, Northern District of California, against the Company
and Pacific Gas Transmission Company (PGT), a wholly owned subsidiary
of the Company. Norcen Marketing has a 30-year gas transportation
contract with PGT, which is guaranteed by Norcen Energy. The
complaint alleged that PGT and the Company wrongfully induced Norcen
Energy and Norcen Marketing to enter into the 30-year contract by
concealing legal action taken by the Company before the CPUC
(requesting clarification that gas shipped on the PGT portion of the
Pipeline Expansion should pay the Company's incremental Expansion
rates for in-state service) two days before Norcen Marketing's
contract became binding. The complaint also alleged breach of
representations to plaintiffs that the Company would not
"unreasonably" build its Pipeline Expansion with less than
"sufficient" firm subscription and a breach of an agreement between
PGT and a Norcen predecessor relating to the installation of
additional capacity. In addition to state law contract claims, the
complaint also alleged a series of federal and state antitrust claims
related to the construction of the Pipeline Expansion and the
Company's alleged refusals to allow access to the original PGT and
California transmission systems. Those antitrust claims were
dismissed by the Court in September 1994, and subsequently reasserted
in part by plaintiffs in an amended complaint filed in October 1994.
On July 27, 1995, the District Court issued an order on the Company's
motion to dismiss the amended complaint. The order dismisses all of
plaintiffs' federal and state antitrust claims, but does not dismiss
various state law contract claims, including claims based on
fraudulent inducement and breach of contract. In addition to
recission of their gas transportation contract, the plaintiffs are
seeking an unspecified amount of contract damages. Based on
available information, plaintiffs' out-of-pocket contract damages
appear to be less than $10 million. The plaintiffs are also seeking
punitive damages in connection with the remaining state law claims.
The Company believes that the ultimate outcome of this matter will
not have a significant adverse impact on its financial position or
results of operations.
Item 5. Other Information
-----------------
Ratios of Earnings to Fixed Charges and Ratios of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
The Company's earnings to fixed charges ratio for the six months
ended June 30, 1995 was 4.47. The Company's earnings to combined
fixed charges and preferred stock dividends ratio for the six months
ended June 30, 1995 was 3.97. 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 June 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 second quarter of 1995 and
through the date hereof:
1. 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 Proceedings
- Electric Fuel and Sales Balancing Accounts -
ECAC/ERAM
- Biennial Cost Allocation Proceeding (BCAP)
D. Sale of DALEN Resources Corp.
2. May 17, 1995
Item 5. Other Events
A. California Public Utilities Commission Proceedings
- Diablo Canyon Rate Case Settlement
3. May 23, 1995
Item 5. Other Events
A. Potential Acquisition of United Energy Limited
4. May 26, 1995
Item 5. Other Events
A. California Public Utilities Commission Proceedings
- Electric Industry Restructuring
- Diablo Canyon Rate Case Settlement
- Biennial Cost Allocation Proceeding
- Experimental Procurement Service for Customer-
Identified Electric Supply
B. Common Stock Repurchase Program
5. July 14, 1995
Item 5. Other Events
A. Gas Restructuring and Settlement Proposal
6. July 20, 1995
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
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
August 11, 1995 GORDON R. SMITH
By________________________________
GORDON R. SMITH
Senior Vice President and Chief
Financial Officer
EXHIBIT INDEX
Exhibit
Number Exhibit
------- ---------------------------------------
3 By-Laws as amended June 1, 1995
11 Computation of Earnings Per
Common Share
12.1 Computation of Ratios of Earnings
to Fixed Charges
12.2 Computation of Ratios of Earnings
to Combined Fixed Charges and Preferred
Stock Dividends
27 Financial Data Schedule
Bylaws
of
Pacific Gas and Electric Company
as amended JUNE 1, 1995
Article I.
SHAREHOLDERS.
1. Place of Meeting. All meetings of the shareholders shall be held
at the office of the Corporation in the City and County of San Francisco,
State of California, or at such other place within the State of California
as may be designated by the Board of Directors.
2. Annual Meetings. The annual meeting of shareholders shall be
held each year on a date and at a time designated by the Board of
Directors.
Written notice of the annual meeting shall be given not less than ten
(or, if sent by third-class mail, thirty) nor more than sixty days prior to
the date of the meeting to each shareholder entitled to vote thereat. The
notice shall state the place, day, and hour of such meeting, and those
matters which the Board, at the time of mailing, intends to present for
action by the shareholders.
Notice of any meeting of the shareholders shall be given by mail or
telegraphic or other written communication, postage prepaid, to each holder
of record of the stock entitled to vote thereat, at his address, as it
appears on the books of the Corporation.
3. Special Meetings. Special meetings of the shareholders shall be
called by the Secretary or an Assistant Secretary at any time on order of
the Board of Directors, the Chairman of the Board, the Vice Chairman of the
Board, the Chairman of the Executive Committee, or the President. Special
meetings of the shareholders shall also be called by the Secretary or an
Assistant Secretary upon the written request of holders of shares entitled
to cast not less than ten percent of the votes at the meeting. Such
request shall state the purposes of the meeting, and shall be delivered to
the Chairman of the Board, the Vice Chairman of the Board, the Chairman of
the Executive Committee, the President or the Secretary.
A special meeting so requested shall be held on the date requested,
but not less than thirty-five nor more than sixty days after the date of
the original request. Written notice of each special meeting of
shareholders, stating the place, day, and hour of such meeting and the
business proposed to be transacted thereat, shall be given in the manner
stipulated in Article I, Section 2, Paragraph 3 of these Bylaws within
twenty days after receipt of the written request.
4. Attendance at Meetings. At any meeting of the shareholders,
each holder of record of stock entitled to vote thereat may attend in
person or may designate an agent or a reasonable number of agents, not to
exceed three to attend the meeting and cast votes for his shares. The
authority of agents must be evidenced by a written proxy signed by the
shareholder designating the agents authorized to attend the meeting and be
delivered to the Secretary of the Corporation prior to the commencement of
the meeting.
5. No Cumulative Voting. No shareholder of the Corporation shall
be entitled to cumulate his or her voting power.
Article II.
DIRECTORS.
1. Number. The Board of Directors shall consist of seventeen (17)
directors.
2. Powers. The Board of Directors shall exercise all the powers
of the Corporation except those which are by law, or by the Articles of
Incorporation of this Corporation, or by the Bylaws conferred upon or
reserved to the shareholders.
3. Executive Committee. There shall be an Executive Committee of
the Board of Directors consisting of the Chairman of the Committee, the
Chairman of the Board, if these offices be filled, the President, and five
Directors who are not officers of the Corporation. The members of the
Committee shall be elected, and may at any time be removed, by a two-thirds
vote of the whole Board.
The Executive Committee, subject to the provisions of law, may
exercise any of the powers and perform any of the duties of the Board of
Directors; but the Board may by an affirmative vote of a majority of its
members withdraw or limit any of the powers of the Executive Committee.
The Executive Committee, by a vote of a majority of its members, shall
fix its own time and place of meeting, and shall prescribe its own rules of
procedure. A quorum of the Committee for the transaction of business shall
consist of three members.
4. Time and Place of Directors' Meetings. Regular meetings of the
Board of Directors shall be held on such days and at such times and at such
locations as shall be fixed by resolution of the Board, or designated by
the Chairman of the Board or, in his absence, the Vice Chairman of the
Board, or the President of the Corporation and contained in the notice of
any such meeting. Notice of meetings shall be delivered personally or sent
by mail or telegram at least seven days in advance.
5. Special Meetings. The Chairman of the Board, the Vice Chairman
of the Board, the Chairman of the Executive Committee, the President, or
any five directors may call a special meeting of the Board of Directors at
any time. Notice of the time and place of special meetings shall be given
to each Director by the Secretary. Such notice shall be delivered
personally or by telephone to each Director at least four hours in advance
of such meeting, or sent by first-class mail or telegram, postage prepaid,
at least two days in advance of such meeting.
6. Quorum. A quorum for the transaction of business at any meeting
of the Board of Directors shall consist of six members.
7. Action by Consent. Any action required or permitted to be taken
by the Board of Directors may be taken without a meeting if all Directors
individually or collectively consent in writing to such action. Such
written consent or consents shall be filed with the minutes of the
proceedings of the Board of Directors.
8. Meetings by Conference Telephone. Any meeting, regular or
special, of the Board of Directors or of any committee of the Board of
Directors, may be held by conference telephone or similar communication
equipment, provided that all Directors participating in the meeting can
hear one another.
Article III.
OFFICERS.
1. Officers. The officers of the Corporation shall be a Chairman of
the Board, a Vice Chairman of the Board, a Chairman of the Executive
Committee (whenever the Board of Directors in its discretion fills these
offices), a President, one or more Vice Presidents, a Secretary and one or
more Assistant Secretaries, a Treasurer and one or more Assistant
Treasurers, a General Counsel, a General Attorney (whenever the Board of
Directors in its discretion fills this office), and a Controller, all of
whom shall be elected by the Board of Directors. The Chairman of the
Board, the Vice Chairman of the Board, the Chairman of the Executive
Committee, and the President shall be members of the Board of Directors.
2. Chairman of the Board. The Chairman of the Board, if that
office be filled, shall preside at all meetings of the shareholders, of the
Directors, and of the Executive Committee in the absence of the Chairman of
that Committee. He shall be the chief executive officer of the Corporation
if so designated by the Board of Directors. He shall have such duties and
responsibilities as may be prescribed by the Board of Directors or the
Bylaws. The Chairman of the Board shall have authority to sign on behalf
of the Corporation agreements and instruments of every character, and in
the absence or disability of the President, shall exercise his duties and
responsibilities.
3. Vice Chairman of the Board. The Vice Chairman of the Board, if
that office be filled, shall have such duties and responsibilities as may
be prescribed by the Board of Directors, the Chairman of the Board, or the
Bylaws. He shall be the chief executive officer of the Corporation if so
designated by the Board of Directors. In the absence of the Chairman of
the Board, he shall preside at all meetings of the Board of Directors and
of the shareholders; and, in the absence of the Chairman of the Executive
Committee and the Chairman of the Board, he shall preside at all meetings
of the Executive Committee. The Vice Chairman of the Board shall have
authority to sign on behalf of the Corporation agreements and instruments
of every character.
4. Chairman of the Executive Committee. The Chairman of the
Executive Committee, if that office be filled, shall preside at all
meetings of the Executive Committee. He shall aid and assist the other
officers in the performance of their duties and shall have such other
duties as may be prescribed by the Board of Directors or the Bylaws.
5. President. The President shall have such duties and
responsibilities as may be prescribed by the Board of Directors, the
Chairman of the Board, or the Bylaws. He shall be the chief executive
officer of the Corporation if so designated by the Board of Directors. If
there be no Chairman of the Board, the President shall also exercise the
duties and responsibilities of that office. The President shall have
authority to sign on behalf of the Corporation agreements and instruments
of every character.
6. Vice Presidents. Each Vice President shall have such duties and
responsibilities as may be prescribed by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the President, or
the Bylaws. Each Vice President's authority to sign agreements and
instruments on behalf of the Corporation shall be as prescribed by the
Board of Directors. The Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, or the President may confer a special title
upon any Vice President.
7. Secretary. The Secretary shall attend all meetings of the Board
of Directors and the Executive Committee, and all meetings of the
shareholders, and he shall record the minutes of all proceedings in books
to be kept for that purpose. He shall be responsible for maintaining a
proper share register and stock transfer books for all classes of shares
issued by the Corporation. He shall give, or cause to be given, all
notices required either by law or the Bylaws. He shall keep the seal of
the Corporation in safe custody, and shall affix the seal of the
Corporation to any instrument requiring it and shall attest the same by his
signature.
The Secretary shall have such other duties as may be prescribed by the
Board of Directors, the Chairman of the Board, the Vice Chairman of the
Board, the President, or the Bylaws.
The Assistant Secretaries shall perform such duties as may be assigned
from time to time by the Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, the President, or the Secretary. In the
absence or disability of the Secretary, his duties shall be performed by an
Assistant Secretary.
8. Treasurer. The Treasurer shall have custody of all moneys and
funds of the Corporation, and shall cause to be kept full and accurate
records of receipts and disbursements of the Corporation. He shall deposit
all moneys and other valuables of the Corporation in the name and to the
credit of the Corporation in such depositaries as may be designated by the
Board of Directors or any employee of the Corporation designated by the
Board of Directors. He shall disburse such funds of the Corporation as
have been duly approved for disbursement.
The Treasurer shall perform such other duties as may from time to time
be prescribed by the Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, the President, or the Bylaws.
The Assistant Treasurer shall perform such duties as may be assigned
from time to time by the Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, the President, or the Treasurer. In the
absence or disability of the Treasurer, his duties shall be performed by an
Assistant Treasurer.
9. General Counsel. The General Counsel shall be responsible for
handling on behalf of the Corporation all proceedings and matters of a
legal nature. He shall render advice and legal counsel to the Board of
Directors, officers, and employees of the Corporation, as necessary to the
proper conduct of the business. He shall keep the management of the
Corporation informed of all significant developments of a legal nature
affecting the interests of the Corporation.
The General Counsel shall have such other duties as may from time to
time be prescribed by the Board of Directors, the Chairman of the Board,
the Vice Chairman of the Board, the President, or the Bylaws.
10. Controller. The Controller shall be responsible for maintaining
the accounting records of the Corporation and for preparing necessary
financial reports and statements, and he shall properly account for all
moneys and obligations due the Corporation and all properties, assets, and
liabilities of the Corporation. He shall render to the officers such
periodic reports covering the result of operations of the Corporation as
may be required by them or any one of them.
The Controller shall have such other duties as may from time to time
be prescribed by the Board of Directors, the Chairman of the Board, the
Vice Chairman of the Board, the President, or the Bylaws.
Article IV.
MISCELLANEOUS.
1. Record Date. The Board of Directors may fix a time in the
future as a record date for the determination of the shareholders entitled
to notice of and to vote at any meeting of shareholders, or entitled to
receive any dividend or distribution, or allotment of rights, or to
exercise rights in respect to any change, conversion, or exchange of
shares. The record date so fixed shall be not more than sixty nor less
than ten days prior to the date of such meeting nor more than sixty days
prior to any other action for the purposes for which it is so fixed. When
a record date is so fixed, only shareholders of record on that date are
entitled to notice of and to vote at the meeting, or entitled to receive
any dividend or distribution, or allotment of rights, or to exercise the
rights, as the case may be.
2. Transfers of Stock. Upon surrender to the Secretary or Transfer
Agent of the Corporation of a certificate for shares duly endorsed or
accompanied by proper evidence of succession, assignment, or authority to
transfer, and payment of transfer taxes, the Corporation shall issue a new
certificate to the person entitled thereto, cancel the old certificate, and
record the transaction upon its books. Subject to the foregoing, the Board
of Directors shall have power and authority to make such rules and
regulations as it shall deem necessary or appropriate concerning the issue,
transfer, and registration of certificates for shares of stock of the
Corporation, and to appoint and remove Transfer Agents and Registrars of
transfers.
3. Lost Certificates. Any person claiming a certificate of stock
to be lost, stolen, mislaid, or destroyed shall make an affidavit or
affirmation of that fact and verify the same in such manner as the Board of
Directors may require, and shall, if the Board of Directors so requires,
give the Corporation, its Transfer Agents, Registrars, and/or other agents
a bond of indemnity in form approved by counsel, and in amount and with
such sureties as may be satisfactory to the Secretary of the Corporation,
before a new certificate may be issued of the same tenor and for the same
number of shares as the one alleged to have been lost, stolen, mislaid, or
destroyed.
4. Employee's Stock Purchase Plan. Subject to any limitation
contained in the Articles of Incorporation, the Board of Directors may in
it discretion, from time to time, authorize the issue and sale of shares of
capital stock of this Corporation to employees, pursuant to an employee's
stock purchase plan, for such consideration as the Board shall determine to
be reasonable. Such plan may provide for payment for such shares by
installments over a period of time fixed by the Board. In any such plan,
the Board may provide for interest on any installment payments, and that an
employee may cancel his agreement to purchase all or part of the shares
thereunder. The Board may fix such other terms and conditions for any such
plan as it shall deem, in its discretion, to be in the best interests of
this Corporation. Any such plan may include employees of: This
Corporation's subsidiaries and affiliates; Pacific Service Employees
Association; Pacific Service Employees Credit Union; and such other
associated organizations as may be approved by the Board.
Article V.
AMENDMENTS.
1. Amendment by Shareholders. Except as otherwise provided by law,
these Bylaws, or any of them, may be amended or repealed or new Bylaws
adopted by the affirmative vote of a majority of the outstanding shares
entitled to vote at any regular or special meeting of the shareholders.
2. Amendment by Directors. To the extent provided by law, these
Bylaws, or any of them, may be amended or repealed or new Bylaws adopted by
resolution adopted by a majority of the members of the Board of Directors.
S:...\adminsvcs\board\BYLAWS.doc [6]
<TABLE>
EXHIBIT 11
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
(unaudited)
<CAPTION>
--------------------------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
-------------------- --------------------
(in thousands, except per share amounts) 1995 1994 1995 1994
--------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income $405,520 $241,365 $734,207 $478,317
Less preferred dividends 14,494 14,362 28,988 28,820
Net income for calculating EPS for -------- -------- -------- --------
Statement of Consolidated Income $391,026 $227,003 $705,219 $449,497
======== ======== ======== ========
Average common shares outstanding 426,621 429,762 428,344 429,150
======== ======== ======== ========
EPS as shown in the Statement of
Consolidated Income $ .92 $ .53 $ 1.65 $ 1.05
======== ======== ======== ========
PRIMARY EPS (1)
Net income $405,520 $241,365 $734,207 $478,317
Less: preferred dividends 14,494 14,362 28,988 28,820
amortization of premium on preferred
stock redemption 1,167 1,167
-------- -------- -------- --------
Net income for calculating primary EPS $389,859 $227,003 $704,052 $449,497
======== ======== ======== ========
Average common shares outstanding 426,621 429,762 428,344 429,150
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) 133 520 88 626
-------- -------- -------- --------
Average common shares outstanding as
adjusted 426,754 430,282 428,432 429,776
======== ======== ======== ========
Primary EPS $ .91 $ .53 $ 1.64 $ 1.05
======== ======== ======== ========
FULLY DILUTED EPS (1)
Net income $405,520 $241,365 $734,207 $478,317
Less: preferred dividends 14,494 14,362 28,988 28,820
amortization of premium preferred
stock redemption 1,167 1,167
-------- -------- -------- --------
Net income for calculating fully diluted EPS $389,859 $227,003 $704,052 $449,497
======== ======== ======== ========
Average common shares outstanding 426,621 429,762 428,344 429,150
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) 184 520 184 626
-------- -------- -------- --------
Average common shares outstanding as
adjusted 426,805 430,282 428,528 429,776
======== ======== ======== ========
Fully diluted EPS $ .91 $ .53 $ 1.64 $ 1.05
======== ======== ======== ========
--------------------------------------------------------------------------------------------
<FN>
(1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K.
This presentation is not required by APB Opinion No. 15, because it results in dilution
of less than 3%.
</TABLE>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
---------------------------------------------------------------------------------------------------
Six Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) June 30, 1995 1994 1993 1992 1991 1990
---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 734,207 $1,007,450 $1,065,495 $1,170,581 $1,026,392 $ 987,170
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates (2,447) (2,764) 6,895 (3,349) 26,671 (2,799)
Income tax expense 510,831 836,767 901,890 895,126 851,534 881,647
Net fixed charges 357,334 730,965 821,166 802,198 776,682 812,568
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $1,599,925 $2,572,418 $2,795,446 $2,864,556 $2,681,279 $2,678,586
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-term
debt $ 324,572 $ 651,912 $ 731,610 $ 739,279 $ 697,185 $ 699,849
Interest on short-term
borrowings 31,536 77,295 87,819 61,182 77,760 110,982
Interest on capital
leases 1,056 1,758 1,737 1,737 1,737 1,737
Capitalized Interest 173 2,660 46,055 6,511 6,107 7,214
Pretax earnings required to
cover the preferred stock
dividend requirements of
majority owned subsidiaries 288 - - - - -
-------- ---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $ 357,625 $ 733,625 $ 867,221 $ 808,709 $ 782,789 $ 819,782
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 4.47 3.51 3.22 3.54 3.43 3.27
---------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing the Company's ratios of earnings to fixed charges, "earnings"
represent net income adjusted for the minority interest in losses of less than 100% owned
affiliates, the Company's equity in undistributed income or loss of less than 50% owned
affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed charges"
include interest on long-term debt, short-term borrowings (including a representative portion
of rental expense), amortization of bond premium, discount and expense, interest on capital
leases and the pretax earnings required to cover the preferred stock dividend requirements of
majority owned subsidiaries.
</TABLE>
<TABLE>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
---------------------------------------------------------------------------------------------------
Six Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) June 30, 1995 1994 1993 1992 1991 1990
---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 734,207 $1,007,450 $1,065,495 $1,170,581 $1,026,392 $ 987,170
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates (2,447) (2,764) 6,895 (3,349) 26,671 (2,799)
Income tax expense 510,831 836,767 901,890 895,126 851,534 881,647
Net fixed charges 357,334 730,965 821,166 802,198 776,682 812,568
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $1,599,925 $2,572,418 $2,795,446 $2,864,556 $2,681,279 $2,678,586
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 324,572 $ 651,912 $ 731,610 $ 739,279 $ 697,185 $ 699,849
Interest on short-
term borrowings 31,536 77,295 87,819 61,182 77,760 110,982
Interest on capital
leases 1,056 1,758 1,737 1,737 1,737 1,737
Capitalized Interest 173 2,660 46,055 6,511 6,107 7,214
Pretax earnings required to
cover the preferred stock
dividend requirements of
majority owned subsidiaries 288 - - - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 357,625 733,625 867,221 808,709 782,789 819,782
---------- ---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 5,841 4,672 4,814 5,136 5,136 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 39,252 96,039 108,937 130,147 154,404 175,881
---------- ---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 45,093 100,711 113,751 135,283 159,540 181,017
---------- ---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and
Preferred Stock
Dividends $ 402,718 $ 834,336 $ 980,972 $ 943,992 $ 942,329 $1,000,799
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed
Charges and Preferred
Stock Dividends 3.97 3.08 2.85 3.03 2.85 2.68
---------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing the Company's ratios of earnings to combined fixed charges and
preferred stock dividends, "earnings" represent net income adjusted for the minority interest
in losses of less than 100% owned affiliates, the Company's equity in undistributed income or
loss of less than 50% owned affiliates, income taxes and fixed charges (excluding capitalized
interest). "Fixed charges" include interest on long-term debt, short-term borrowings (including
a representative portion of rental expense), amortization of bond premium, discount and expense,
interest on capital leases and the pretax earnings required to cover the preferred stock dividend
requirements of majority owned subsidiaries. "Preferred stock dividends" represent the sum of
requirements for preferred stock dividends that are deductible for federal income tax purposes
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> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> JUN-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 19,106,527
<OTHER-PROPERTY-AND-INVEST> 1,637,677
<TOTAL-CURRENT-ASSETS> 3,383,082
<TOTAL-DEFERRED-CHARGES> 2,823,631
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 26,950,917
<COMMON> 2,119,100
<CAPITAL-SURPLUS-PAID-IN> 3,789,881
<RETAINED-EARNINGS> 2,820,278
<TOTAL-COMMON-STOCKHOLDERS-EQ> 8,729,259
137,500
732,995
<LONG-TERM-DEBT-NET> 8,250,722
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 210,000
<LONG-TERM-DEBT-CURRENT-PORT> 416,939
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 8,473,502
<TOT-CAPITALIZATION-AND-LIAB> 26,950,917
<GROSS-OPERATING-REVENUE> 4,755,081
<INCOME-TAX-EXPENSE> 570,147
<OTHER-OPERATING-EXPENSES> 3,196,097
<TOTAL-OPERATING-EXPENSES> 3,766,244
<OPERATING-INCOME-LOSS> 988,837
<OTHER-INCOME-NET> 92,196
<INCOME-BEFORE-INTEREST-EXPEN> 1,081,033
<TOTAL-INTEREST-EXPENSE> 346,826
<NET-INCOME> 734,207
28,988
<EARNINGS-AVAILABLE-FOR-COMM> 705,219
<COMMON-STOCK-DIVIDENDS> 421,128
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 1,868,568
<EPS-PRIMARY> 1.64
<EPS-DILUTED> 1.64
</TABLE>
