FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
---------------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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
- ---------------------------- -------------------
(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 November 3, 1995
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Common Stock, $5 par value 419,026,849 shares
Form 10-Q
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TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION Page
- ------------------------------- ----
Item 1. Consolidated Financial Statements and Notes
Statement of Consolidated Income................... 1
Consolidated Balance Sheet......................... 2
Statement of Consolidated Cash Flows............... 4
Note 1: General
Basis of Presentation................... 5
Workforce Reductions.................... 5
Note 2: Electric Industry Restructuring........... 6
Note 3: Natural Gas Matters
Gas Reasonableness Proceedings.......... 11
Transwestern Commitment................. 12
Gas Accord Negotiations................. 12
Note 4: Diablo Canyon............................. 13
Note 5: Contingencies
Nuclear Insurance....................... 14
Environmental Remediation............... 14
Legal Matters........................... 15
Item 2. Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Competition and Changing Regulatory Environment.... 18
Holding Company Proposal........................... 20
Results of Operations
Earnings Per Common Share........................ 22
Common Stock Dividend............................ 22
Operating Revenues............................... 23
Operating Expenses............................... 23
Other Income and (Income Deductions)............. 24
Regulatory Matters............................... 24
Nonregulated Operations.......................... 26
Liquidity and Capital Resources
Sources of Capital............................... 26
Risk Management.................................. 27
Investing and Financing Activity................. 27
Environmental Remediation........................ 27
Legal Matters.................................... 28
Other Matters
New Accounting Standard.......................... 28
Accounting for Decommissioning Expense........... 29
PART II. OTHER INFORMATION
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Item 1. Legal Proceedings.................................. 30
Time-of-Use Meter Customer Notification
Litigation..................................... 30
Cities Franchise Fees Litigaiton................... 30
Coastal League Litigation.......................... 31
California Attorney General Investigation.......... 31
Item 5. Helms Pumped Storage Plant......................... 32
Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends............ 33
Item 6. Exhibits and Reports on Form 8-K................... 33
SIGNATURE...................................................... 34
PART I. FINANCIAL INFORMATION
------------------------------
Item 1. Consolidated Financial Statements
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<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
Three months ended September 30, Nine months ended September 30,
(in thousands, ------------------------------- ------------------------------
except per share amounts) 1995 1994 1995 1994
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric $2,140,347 $2,356,034 $5,730,699 $6,076,242
Gas 478,806 446,552 1,528,745 1,572,880
Other 26,070 52,635 140,860 160,050
---------- ---------- ---------- ----------
Total operating revenues 2,645,223 2,855,221 7,400,304 7,809,172
---------- ---------- ---------- ----------
OPERATING EXPENSES
Cost of electric energy 728,070 862,962 1,717,354 2,149,442
Cost of gas 52,860 74,514 239,772 409,278
Distribution 51,945 41,290 137,801 154,270
Transmission 59,128 63,025 184,603 200,071
Customer accounts and services 109,462 95,532 313,146 282,086
Maintenance 114,994 93,942 298,865 323,096
Depreciation and
decommissioning 328,753 347,867 1,025,229 1,041,610
Administrative and general 273,956 234,291 749,669 697,279
Workforce reductions - - (18,195) -
Income taxes 296,562 347,939 866,709 808,532
Property and other taxes 74,631 71,267 224,603 227,506
Other 49,236 37,898 166,285 120,929
---------- ---------- ---------- ----------
Total operating expenses 2,139,597 2,270,527 5,905,841 6,414,099
---------- ---------- ---------- ----------
OPERATING INCOME 505,626 584,694 1,494,463 1,395,073
---------- ---------- ---------- ----------
OTHER INCOME AND (INCOME
DEDUCTIONS)
Interest income 17,570 13,810 50,515 35,732
Allowance for equity funds
used during construction 5,592 5,042 17,692 14,779
Other--net 11,877 (1,463) 59,028 (5,229)
---------- ---------- ---------- ----------
Total other income and
(income deductions) 35,039 17,389 127,235 45,282
---------- ---------- ---------- ----------
INCOME BEFORE INTEREST EXPENSE 540,665 602,083 1,621,698 1,440,355
---------- ---------- ---------- ----------
INTEREST EXPENSE
Interest on long-term debt 153,999 164,156 478,571 487,348
Other interest charges 12,122 15,928 40,459 60,465
Allowance for borrowed funds
used during construction (3,049) (3,634) (9,132) (11,408)
---------- ---------- ---------- ----------
Net interest expense 163,072 176,450 509,898 536,405
---------- ---------- ---------- ----------
NET INCOME 377,593 425,633 1,111,800 903,950
Preferred dividend requirement 15,901 14,494 44,889 43,314
---------- ---------- ---------- ----------
EARNINGS AVAILABLE FOR
COMMON STOCK $ 361,692 $ 411,139 $1,066,911 $ 860,636
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING 421,578 430,439 426,064 429,584
EARNINGS PER COMMON SHARE $.85 $.96 $2.50 $2.00
DIVIDENDS DECLARED PER COMMON SHARE $.49 $.49 $1.47 $1.47
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
September 30, December 31,
(in thousands) 1995 1994
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<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $ 17,480,211 $ 17,045,247
Diablo Canyon 6,672,534 6,647,162
Gas 7,691,905 7,447,879
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Total plant in service (at original cost) 31,844,650 31,140,288
Accumulated depreciation and decommissioning (13,309,716) (12,269,377)
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Net plant in service 18,534,934 18,870,911
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CONSTRUCTION WORK IN PROGRESS 455,241 527,867
OTHER NONCURRENT ASSETS
Oil and gas properties - 437,352
Nuclear decommissioning funds 730,284 616,637
Investment in nonregulated projects 819,492 761,355
Other 148,241 137,325
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Total other noncurrent assets 1,698,017 1,952,669
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CURRENT ASSETS
Cash and cash equivalents 338,755 136,900
Accounts receivable
Customers 1,362,499 1,413,185
Other 72,495 98,035
Allowance for uncollectible accounts (32,567) (29,769)
Regulatory balancing accounts receivable 1,075,410 1,345,669
Inventories
Materials and supplies 176,708 197,394
Gas stored underground 153,284 136,326
Fuel oil 43,129 67,707
Nuclear fuel 157,625 140,357
Prepayments 38,323 33,251
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Total current assets 3,385,661 3,539,055
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DEFERRED CHARGES
Income tax-related deferred charges 1,090,955 1,155,421
Diablo Canyon costs 386,999 401,110
Unamortized loss net of gain on reacquired debt 384,405 382,862
Workers' compensation and disability claims recoverable 247,065 247,209
Other 697,653 732,029
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Total deferred charges 2,807,077 2,918,631
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TOTAL ASSETS $ 26,880,930 $ 27,809,133
============ ============
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<FN>
(continued on next page)
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
September 30, December 31,
(in thousands) 1995 1994
- --------------------------------------------------------------------------------------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,091,930 $ 2,151,213
Additional paid-in capital 3,740,433 3,806,508
Reinvested earnings 2,879,978 2,677,304
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Total common stock equity 8,712,341 8,635,025
Preferred stock without mandatory redemption provision 582,995 732,995
Preferred stock with mandatory redemption provision 137,500 137,500
Long-term debt 8,207,071 8,675,091
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Total capitalization 17,639,907 18,180,611
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OTHER NONCURRENT LIABILITIES
Customer advances for construction 147,410 152,384
Workers' compensation and disability claims 221,200 221,200
Other 827,649 644,233
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Total other noncurrent liabilities 1,196,259 1,017,817
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CURRENT LIABILITIES
Short-term borrowings 106,304 524,685
Long-term debt 444,715 477,047
Accounts payable
Trade creditors 368,367 414,291
Other 420,410 337,726
Accrued taxes 591,419 436,467
Deferred income taxes 286,206 432,026
Interest payable 172,224 84,805
Dividends payable 219,828 210,903
Other 487,922 643,779
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Total current liabilities 3,097,395 3,561,729
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DEFERRED CREDITS
Deferred income taxes 3,802,305 3,902,645
Deferred investment tax credits 377,936 391,455
Noncurrent balancing account liabilities 187,879 226,844
Other 579,249 528,032
----------- -----------
Total deferred credits 4,947,369 5,048,976
CONTINGENCIES (Notes 2, 3 and 5) - -
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TOTAL CAPITALIZATION AND LIABILITIES $26,880,930 $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>
- --------------------------------------------------------------------------------------------
Nine months ended September 30,
------------------------------
(in thousands) 1995 1994
- --------------------------------------------------------------------------------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 1,111,800 $ 903,950
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and decommissioning 1,025,229 1,041,610
Amortization 128,463 83,520
Gain on sale of DALEN (13,107) -
Deferred income taxes and investment tax credits--net (189,512) 275,459
Allowance for equity funds used during construction (17,692) (14,779)
Other deferred charges 10,134 35,274
Other noncurrent liabilities 142,294 206,183
Noncurrent balancing account liabilities and
other deferred credits 12,252 102,590
Net effect of changes in operating assets
and liabilities
Accounts receivable 79,024 (18,150)
Regulatory balancing accounts receivable 270,259 (415,991)
Inventories 28,306 (3,566)
Accounts payable 36,760 (16,050)
Accrued taxes 154,952 292,820
Other working capital (73,006) (17,688)
Other--net 50,385 (1,196)
---------- ----------
Net cash provided by operating activities 2,756,541 2,453,986
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (641,897) (686,486)
Allowance for borrowed funds used during construction (9,132) (11,408)
Nonregulated expenditures (107,370) (491,926)
Proceeds from sale of DALEN 340,000 -
Other--net (59,822) 16,625
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Net cash used by investing activities (478,221) (1,173,195)
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CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 116,095 208,654
Common stock repurchased (449,692) (121,277)
Preferred stock issued - 62,312
Preferred stock redeemed (168,130) (83,020)
Long-term debt issued 704,480 55,000
Long-term debt matured or reacquired (1,110,652) (321,620)
Short-term debt--net (418,381) (417,858)
Dividends paid (674,128) (666,453)
Other--net (76,057) 83,919
---------- ----------
Net cash used by financing activities (2,076,465) (1,200,343)
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NET CHANGE IN CASH AND CASH EQUIVALENTS 201,855 80,448
CASH AND CASH EQUIVALENTS AT JANUARY 1 136,900 61,066
---------- ----------
CASH AND CASH EQUIVALENTS AT SEPTEMBER 30 $ 338,755 $ 141,514
========== ==========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 389,934 $ 420,834
Income taxes 849,934 403,219
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
NOTE 1: GENERAL
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Basis of Presentation:
- ---------------------
The accompanying unaudited consolidated financial statements of
Pacific Gas and Electric Company (PG&E) and its wholly owned and
controlled subsidiaries (collectively, the Company) have been
prepared in accordance with interim period reporting requirements.
This information should be read in conjunction with the Consolidated
Financial Statements and Notes to Consolidated Financial Statements
incorporated by reference in the 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 December 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 September 30, 1995, a severance reserve of approximately $11 million
remained. Charges against the reserve will be made for the
approximately 60 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 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 complete 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
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) would be recovered through a
competition transition charge (CTC). However, neither proposal
indicates precisely how the CTC is to be measured or recovered.
Majority Proposal: Under the majority proposal, participants in the
pool would transfer operating control, but not ownership, of their
transmission assets to an independent system operator (ISO). The ISO
would be responsible for transmission scheduling and economic dispatch
of generation. All other power suppliers would be invited to sell to
the pool or purchase from it 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 ISO 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 ISO, 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.
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 there may still
be a need for CTC recovery for Diablo Canyon, although it would be
reduced.
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, if
necessary, 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 would be recovered
through the CTC. 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 assets.
For utility generation 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 Diablo Canyon 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 ten 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.
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.
Since the release of the above proposed policy decisions, the CPUC has
received comments from many parties. In addition, in September 1995, a
Memorandum of Understanding (MOU) setting forth joint recommendations
from Southern California Edison Company and a coalition of independent
power producers and major customers was submitted to the CPUC. The
plan described in the MOU recommends: (1) the simultaneous development
of a power pool or exchange and direct access no later than January 1,
1998, with the phase-in of direct access for retail customers over a
five-year period; (2) creation of an ISO which will manage and provide
access to the transmission system on a nondiscriminatory basis; and (3)
a nonbypassable CTC designed to fully recover past utility investments
and obligations. Although the CPUC has solicited comments on the MOU,
it is unclear at this point how the MOU will influence the
restructuring of the electric industry.
Additionally, the CPUC commissioners have asked for comments on a
number of restructuring issues. In October 1995, in a coordinating
commissioner ruling, commissioners asked participants to comment on the
feasibility of a one-time ten percent rate cut for small customers, a
hypothetical partial divestiture of utility generation assets, and a
number of questions about transmission and dispatch of generation and
grid operations as described in the MOU. The Company's responses to
the MOU and commissioners' questions, essentially repeat and augment
positions taken earlier.
The CPUC held 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 Federal Energy
Regulatory Commission 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
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 $3.4 billion of regulatory assets, including
balancing accounts, at September 30, 1995.
If either CPUC 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 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
$467 million which are expected to be recovered in the near term, were
approximately $1.5 billion at September 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 September 30, 1995. The net book value of the
Company's investment in Diablo Canyon was approximately $4.9 billion at
September 30, 1995.
While neither the majority nor the alternative proposal indicates
precisely how the CTC will be determined, based on the CTC described
included in the two proposals, the Company does not anticipate a
material impairment due to the impending electric industry
restructuring. However, should final regulations differ materially
from these proposals, an impairment loss could 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 September 1995, the federal court denied a motion filed
by the CPUC to dismiss the lawsuit.
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.
In October 1995, a CPUC Administrative Law Judge (ALJ) issued a
proposed decision on the reasonableness of certain of the Company's
operations during 1992. The ALJ recommended adoption of one of the
settlement agreements discussed below for resolution of those 1992 non-
Canadian gas issues covered by that agreement.
In the proposed decision, the ALJ also ordered a disallowance of $18
million of costs associated with the Company's gas transportation
commitment with Transwestern Pipeline Company (Transwestern). This
proposed decision does not constitute a CPUC decision and may be
accepted, modified or rejected by the CPUC in its final decision. (See
further discussion in the Transwestern Commitment section below.)
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 $155 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 two 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.
As of September 30, 1995, the Company has accrued approximately $265
million for gas reasonableness matters. 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.
Settlement of certain other unresolved gas issues is being negotiated
as part of the "Gas Accord" negotiations discussed below.
Transwestern Commitment:
- -----------------------
The Company has a 15-year gas transportation contract with Transwestern
for 200 million cubic feet per day of firm capacity. In a proposed
decision on the reasonableness of the Company's 1992 operations, the
ALJ concluded that it was unreasonable for the Company to subscribe for
transportation capacity with Transwestern. The proposed decision
concluded that the Company was unable to prove the benefits of such
capacity during 1992 and denied recovery of Transwestern charges for
that year. The proposed decision further orders that costs for the
capacity in subsequent years of the contract which expires in 2007 be
disallowed unless the Company can demonstrate that the benefits of the
commitment outweigh the costs. Currently, the annual demand charges
for the Transwestern contract are approximately $28 million. The
Company will contest this proposed decision.
The Company is actively pursuing the resolution of the issue of past
and future Transwestern costs as part of the Gas Accord negotiations
discussed below. The Company believes the ultimate resolution of
Transwestern costs, either through settlement negotiations or future
reasonableness proceedings, will not have a significant adverse impact
on its financial position or results of operations.
Gas Accord Negotiations:
- -----------------------
In October 1995, the Company announced that it had presented a
proposal, called the Gas Accord, to numerous parties active in the
California gas marketplace, including consumer groups, industrial
customers, shippers and marketers. The Company has invited these
parties to join it in a collaborative effort to develop a restructuring
of the California gas market.
The Gas Accord consists of three broad initiatives:
- - Increased Customer Choice
Since 1988, large industrial and commercial customers (noncore
customers) have had the option of buying gas directly from the supplier
of their choice, and only paying the Company for transmission and
distribution services. Residential and small commercial customers
(core customers) have had the same option under a pilot program since
1991. Under the Gas Accord, the Company proposes to give all customers
greater ability to choose their gas suppliers in the future. The
Company proposes to implement a test marketing program with core
customers and to form an advisory group to determine the simplest and
most effective ways for core customers to buy gas directly from any
supplier.
- - Separation of Transmission and Distribution Rates
The Company proposes to separately charge for, or "unbundle," its gas
transmission and distribution services. This would give industrial and
commercial customers and gas suppliers more flexibility with respect to
the purchase of gas transportation services.
- - Resolution of Existing Regulatory Issues
The Company also proposes to settle several outstanding gas regulatory
issues that are currently pending at the CPUC in separate proceedings.
These issues include the Company's capacity commitments with
Transwestern, the Interstate Transition Cost Surcharge case, and the
reasonableness proceeding for the PG&E portion of the PGT/PG&E Pipeline
Expansion Project.
Negotiations on the Gas Accord began in October 1995. Any agreement
reached by the Company and other parties must be approved by the CPUC
before it may be implemented.
The Company believes the ultimate outcome of the Gas Accord
negotiations, including resolution of gas regulatory issues, will not
have a significant impact on its financial position or results of
operation.
NOTE 4: Diablo Canyon
- ----------------------
In May 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 modified
prices for 1995 through 1999 are 11.0 cents, 10.5 cents, 10.0 cents,
9.5 cents, and 9.0 cents per kilowatt-hour, respectively, effective
January 1. 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.
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 suffers a property damage loss or a
business interruption loss due to a prolonged accidental outage, the
Company may be subject to maximum assessments of $28 million
(property damage) and $8 million (business interruption), in each
case per policy period, in the event losses exceed the resources of
NML or NEIL.
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 September 30, 1995, of $108
million for hazardous waste remediation costs. The costs may be as
much as $266 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,
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 September 30, 1995, the Company has paid $50 million to escrow
and reserved an additional $150 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
Court has denied the Company's motion for summary judgment and class
decertification. The case is set for trial in February 1996.
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 $29 million as of September
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
controlled 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. Substantially all of 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.
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 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. 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
complete 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 an immediate and complete divestiture of utility generating
assets or mandated shareholder absorption of a portion of transition
costs associated with generating plants.
Currently, the CPUC is considering a Memorandum of Understanding (MOU)
submitted to the CPUC in September 1995, which sets forth joint
recommendations from Southern California Edison Company and a coalition
of independent power producers and major customers. The plan described
in the MOU recommends the simultaneous development of a power pool or
exchange and direct access no later than January 1, 1998, with the
phase-in of direct access for retail customers over a five-year period.
The plan also includes a nonbypassable CTC designed to fully recover
past utility investments and obligations. Under the MOU plan, an
independent system operator would manage the transmission system and
find the most efficient mix of plants to supply the electricity. The
CPUC has solicited comments on the MOU, but it is uncertain at this
time how it will influence the restructuring of the electric industry.
Additionally, the CPUC commissioners have asked for comments on a
number of restructuring issues, including specific questions about the
MOU. The commissioners request comments on the feasibility of a one-
time ten percent rate cut for small customers, reactions to a
hypothetical partial divestiture of utility generation assets, and
transmission and dispatch procedures and grid operations described in
the MOU. The Company has responded to these questions, essentially
repeating and augmenting earlier positions.
The proposed policy decisions and any modifications 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
competition in electric generation for all customers.
In August 1995, the Company filed comments with the FERC on the NOPR
indicating 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 introduce new
innovative transmission models that would allow utilities to respond
more efficiently to changing market demands. The Company also 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 on 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. 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
October 1995, the Company announced it had presented a proposal, called
the Gas Accord, to numerous parties active in the California gas
marketplace. The Company has invited these parties to join it in a
collaborative effort to develop a restructuring of the California gas
market. The Gas Accord proposes three broad initiatives: (1) increase
in customer choice by promoting the ability of all customers to choose
their gas suppliers, (2) separation, or "unbundling", of rates for gas
transmission and distribution services, and (3) resolution of existing
regulatory issues.
Negotiations on the Gas Accord began in October 1995. Any agreement
reached by the Company and other parties must be approved by the CPUC
before it may be implemented. (See Note 3 of Notes to Consolidated
Financial Statements for further discussion.)
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.
Holding Company Proposal:
- ------------------------
In October 1995, the Board of Directors (Board) of PG&E authorized
management to seek appropriate regulatory approvals for the formation
of a holding company structure. Under such structure, the holders of
common stock of PG&E would become the holders of common stock of a new
holding company which, in turn, would own all the common stock of PG&E.
The debt and preferred stock of PG&E would remain outstanding at the
PG&E level and would not become obligations or securities of the
holding company.
This transaction would not result in any change in the Company's
ownership of California utility operations, which currently are
conducted by PG&E and represent substantially all of the assets,
revenues and earnings of the Company consolidated group. It is
intended that the Company's ownership interest in Pacific Gas
Transmission Company (PGT) and Enterprises, two of the Company's wholly
owned subsidiaries representing approximately ten percent of the
Company's consolidated assets and five percent of the Company's
consolidated revenues and earnings at December 31, 1994, would be
transferred to the holding company.
The Company believes that the formation of a holding company will help
the Company to respond more effectively and efficiently to competitive
changes taking place in the utility industry and to new business
opportunities that may arise from those changes. In this respect, it
is believed that this structure will provide greater financing
flexibility and will enhance the financial separation of regulated and
unregulated businesses.
The Company will be seeking approval of the transaction from the CPUC,
the FERC and the Nuclear Regulatory Commission. PG&E's shareholders
will be asked to approve the transaction at PG&E's next annual meeting
in April 1996. The Company does not expect to complete the process of
forming a holding company structure before mid-1996.
Results of Operations:
- ---------------------
The Company's results of operations for the three-month and nine-month
periods ended September 30, 1995, and 1994, are reflected in the
following table:
<TABLE>
<CAPTION>
THREE MONTHS ENDED
SEPTEMBER 30
Diablo
(in millions, except per share amounts) Utility Canyon Enterprises Total
<S> <C> <C> <C> <C>
1995
Operating revenues $ 2,089 $ 530 $ 26 $ 2,645
Operating expenses 1,773 327 39 2,139
------- ------ ------ -------
Operating income (loss) $ 316 $ 203 $ (13) $ 506
======= ====== ====== =======
Net income (loss) $ 211 $ 168 $ (1) $ 378
======= ====== ====== =======
Earnings per common share $ .46 $ .39 $ .00 $ .85
======= ====== ====== =======
1994
Operating revenues $ 2,205 $ 597 $ 53 $ 2,855
Operating expenses 1,861 357 52 2,270
------- ------ ------ -------
Operating income $ 344 $ 240 $ 1 $ 585
======= ====== ====== =======
Net income $ 206 $ 203 $ 17 $ 426
======= ====== ====== =======
Earnings per common share $ .46 $ .46 $ .04 $ .96
======= ====== ====== =======
NINE MONTHS ENDED
SEPTEMBER 30
Diablo
(in millions, except per share amounts) Utility Canyon Enterprises Total
1995
Operating revenues $ 5,720 $1,539 $ 141 $ 7,400
Operating expenses 4,789 936 181 5,906
------- ------ ------ -------
Operating income (loss) $ 931 $ 603 $ (40) $ 1,494
======= ====== ====== =======
Net income $ 616 $ 490 $ 6 $ 1,112
======= ====== ====== =======
Earnings per common share $ 1.36 $ 1.13 $ .01 $ 2.50
======= ====== ====== =======
Total assets at September 30 $19,637 $5,795 $1,449 $26,881
======= ====== ====== =======
1994
Operating revenues $ 6,219 $1,430 $ 160 $ 7,809
Operating expenses 5,311 939 164 6,414
------- ------ ------ -------
Operating income (loss) $ 908 $ 491 $ (4) $ 1,395
======= ====== ====== =======
Net income $ 521 $ 379 $ 4 $ 904
======= ====== ====== =======
Earnings per common share $ 1.14 $ .85 $ .01 $ 2.00
======= ====== ====== =======
Total assets at September 30 $20,329 $6,091 $1,503 $27,923
======= ====== ====== =======
</TABLE>
Earnings Per Common Share:
- -------------------------
Utility earnings per common share for the three-month period ended
September 30, 1995, remained unchanged from the comparable period of
1994, reflecting charges in 1994 and 1995 for litigation and other
reserves. Utility earnings per common share for the nine-month period
ended September 30, 1995, were higher than for the comparable period in
1994, reflecting charges in 1994 related principally to the CPUC
disallowances in the gas reasonableness proceedings for 1988 through
1990, other gas matters and litigation reserves partially offset by
increases in litigation reserves in 1995.
Earnings per common share for Diablo Canyon for the three-month period
ended September 30, 1995, decreased as compared with the same period in
1994, due to a decline in the price per kilowatt-hour (kWh) as provided
in the modified pricing provisions of the Diablo Canyon rate case
settlement (Diablo Settlement). Earnings per common share for Diablo
Canyon for the nine-month period ended September 30, 1995, increased as
compared with the same period in 1994 due to fewer scheduled refueling
days and unscheduled outages in 1995, partially offset by a decline in
the price per kWh as provided in the modified pricing provisions of the
Diablo Settlement.
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 for the nine-month period ended September 30, 1995. (See
Nonregulated Operations section for further discussion.) In June 1994,
Enterprises entered into multiple contracts to sell certain of its oil
and gas properties resulting in a charge of $.03 per common share.
This charge was offset by a gain of $.03 per common share in the three-
month period ended September 30, 1994, recorded upon closing the sale
of the oil and gas properties referred to above.
Common Stock Dividend:
- ---------------------
In July 1995, the Board 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 utility industry will have on the Company's
ability to increase its dividends in the future.
Operating Revenues:
- ------------------
Electric revenues for the three-month period ended September 30, 1995,
decreased $216 million compared to the same period in 1994, primarily
due to a decrease in balancing account revenues resulting from a
decrease in electric energy costs caused by favorable hydro conditions
and lower natural gas prices. In addition, Diablo Canyon operating
revenues decreased due to a decrease in the price per kWh as provided
in the modified pricing provisions of the Diablo Canyon Settlement.
Electric revenues for the nine-month period ended September 30, 1995,
decreased $346 million compared to the same period in 1994 due to a
decrease in balancing account revenues as discussed above and a
decrease in the price per kWh as provided in the modified pricing
provisions of the Diablo Canyon Settlement. This decrease was offset
by favorable operating revenues from Diablo Canyon resulting from fewer
scheduled refueling days and unscheduled outages in 1995.
In September 1995, the Company commenced a scheduled refueling outage
at Unit 1, which was budgeted to last 45 days. In October 1995, an
electrical short occurred in Unit 1, causing a transformer to catch
fire. The ongoing outage at Unit 1 is currently expected to extend
approximately 8 days beyond its 45-day scheduled duration. Under the
current pricing provided in the Diablo Canyon Settlement, each Diablo
Canyon operating unit contributes approximately $2.9 million in
revenues per day at full operating power in 1995.
Gas revenues for the nine-month period ended September 30, 1995,
decreased $44 million compared to the same period in 1994, primarily
due to a decrease in balancing account revenues resulting from a
decline in the price of gas purchased.
Operating Expenses:
- ------------------
Operating expenses for the three-month and nine-month periods ended
September 30, 1995, decreased $131 million and $508 million,
respectively, compared to the same periods in 1994, primarily due to
the lower cost of electric energy. The cost of electric energy was
$135 million and $432 million less in the three-month and nine-month
periods ended September 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 $170 million in
the nine-month period ended September 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 for the three-month
and nine-month periods ended September 30, 1995, increased $40 million
and $52 million, respectively, compared to the same periods in 1994,
due to an increase in litigation reserves. Income tax expense for the
three-month and nine-month periods ended September 30, 1995, decreased
$51 million and increased $58 million, respectively, compared to the
same periods in 1994, as a direct result of fluctuations in pretax
income.
Other Income and (Income Deductions):
- ------------------------------------
Other -- net for the nine-month period ended September 30, 1994,
included accruals related to the CPUC gas reasonableness proceedings,
including proposed settlement agreements. 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 proposals
(discussed further in Note 2 of Notes to Consolidated Financial
Statements) and various gas proceedings (discussed in Note 3 of Notes
to Consolidated Financial Statements), there are other ongoing
regulatory matters with respect to revenues and costs which will impact
the Company's rates in 1996 and beyond. In October 1995, the assigned
administrative law judge (ALJ) issued a proposed decision in the
Company's 1996 General Rate Case (GRC). (See the 1996 GRC section
below for further discussion.) Based on the ALJ's proposed decision
and the overall consolidation of the outstanding electric cases that
would become effective January 1, 1996, including the energy cost, 1996
GRC, Cost of Capital and various other proceedings, the proposed
electric revenue requirement reflects a decrease of $431 million. The
proposed decision would also result in an overall gas revenue
requirement decrease of $289 million in the various gas proceedings.
Based on the consolidation of the electric cases, the Company had
requested an overall revenue requirement decrease of $267 million. The
Company's overall gas revenue requirement request was a decrease of
$240 million. The more significant of these gas and electric
proceedings are discussed below.
In October 1995, the Company updated its 1996 energy cost application
with the CPUC based on the October 1995 ALJ ruling on resource
assumptions. The update reflects a decrease of $113 million in energy
costs due primarily to lower gas costs, lower Diablo Canyon generation
costs, lower qualifying facility expenses and lower estimated
undercollections in the energy cost and electric revenue balancing
accounts. A final CPUC decision is expected in December 1995.
In October 1995, the ALJ in the 1996 GRC issued a proposed decision in
the revenue requirements phase of the GRC, for base rates effective
January 1, 1996. The decision proposes an electric revenue decrease of
$293 million and a gas decrease of $253 million, compared to rates in
effect in 1995. These amounts include an electric decrease of $44
million and a gas decrease of $14 million for the proposed Cost of
Capital decision discussed below. In its GRC application, the Company
had requested a $129 million decrease in electric revenues and a $204
million decrease in gas revenues. Principal areas in which the
proposed decision differs significantly from the Company's request
include fossil plant decommissioning costs, pension funding, marketing
expenses, and salaries. The Company will file its comments on the
proposed decision in late November 1995. A final decision on the
revenue requirements phase of the application is expected in December
1995. To the extent that 1996 revenues ultimately adopted by the CPUC
are significantly less than that requested by the Company and the
Company is unable to identify additional cost reductions to offset
revenue reductions, earnings in 1996 would decrease.
In September 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 to a
decrease of $32 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 October 1995, an ALJ issued a proposed decision adopting the
Company's and several other intervenor's joint recommendation for the
following cost of capital for 1996:
Capital Weighted
Ratio Cost/Return Cost/Return
------- ----------- -----------
Common equity 48.00% 11.60% 5.57%
Long-term debt 46.50% 7.52% 3.49%
Preferred stock 5.50% 7.79% 0.43%
-----
Total return on
average utility rate base 9.49%
=====
The revenue requirement decrease as a result of the proposed decision
has been reflected in the GRC as discussed above. A final CPUC
decision is expected in late November 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 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.
In June 1995, an ALJ issued an order setting hearings to consider the
market impacts of the PG&E portion of the PGT/PG&E Pipeline Expansion
Project (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 the
market impact 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 transportation operations and a broad range
of gas-related issues arising from various proceedings. (See Gas
Accord Negotiations section of Note 3 of Notes to Consolidated
Financial Statements for further discussion.)
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 in, 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 nine-month period ended
September 30, 1995, the Company issued $116 million of common stock,
primarily through its Dividend Reinvestment Program and Savings Fund
Plan. The Company purchased approximately $450 million of common stock
on the open market during the nine-month period ended September 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, and is
considering the use of financial instruments to mitigate commodity
price risks.
Investing and Financing Activity:
- --------------------------------
During the nine-month period ended September 30, 1995, the Company's
capital expenditures were $642 million. This represents a $45 million
decrease from the same period in the preceding year.
During the nine-month period ended September 30, 1995, the Company
redeemed or repurchased $1,111 million of long-term debt and preferred
stock with an aggregate par value of $150 million.
During the nine-month period ended September 30, 1995, PGT, a wholly
owned subsidiary of PG&E, completed the sale of $400 million of debt
securities. Additionally, PGT issued commercial paper and medium-term
notes, $150 million of which was outstanding at September 30, 1995.
The commercial paper is supported by a five-year $200 million bank
revolving credit agreement. The commercial paper outstanding at
September 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.
In October 1995, the Company announced the commencement of a tender
offer to purchase 12.6 million shares of its 7.44%, 7.04% and 6-7/8%
series of preferred stock currently outstanding. The Company's tender
offer includes a premium over par value of approximately $11 million.
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 September 30,
1995, of $108 million for hazardous waste remediation costs. The costs
could be as much as $266 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 CTC recovery 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 any of its assets and specifically,
its generation-related regulatory assets and investments in electric
generation assets.
However, final regulations associated with the electric industry
restructuring discussed above could result in an impairment loss
related to generation assets.
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 and the Form 10-Q for the quarter ended
June 30, 1995, in July 1994 five individuals filed suit 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
claims of two individuals have since been dropped. On June 8, 1995,
the three remaining plaintiffs filed an amended complaint which
alleged 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 estimated 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 was at least an additional $10 billion.
The amended complaint also sought $100 billion in exemplary damages
relating to the Company's alleged willful failure to provide required
notice to customers of rate options.
On October 18, 1995, the Court issued an order granting the Company's
motion to strike the class, leaving only the claims of the
individuals, and granting summary judgment against one of the three
remaining plaintiffs. The Court rejected the Company's assertion that
the California Public Utilities Commission (CPUC) has exclusive
jurisdiction over this dispute, but held that the Company does not
have an obligation to advise customers of their best available rates
and is only obligated to give customers notice of rate options. The
Court's order gives the remaining two plaintiffs an opportunity to
amend their complaint to state a claim based upon an alleged failure
to give them notice of available rate options.
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. Cities Franchise Fees Litigation
As previously reported in the Company's Form 10-K for the fiscal year
ended December 31, 1994, in May 1994, the City of Santa Cruz filed a
complaint in Santa Cruz County Superior Court against the Company on
behalf of itself and purportedly as a class action on behalf of 107
cities with which the Company has certain electric franchise
contracts. The complaint alleges that, since at least 1987, the
Company has intentionally underpaid its franchise fees to the cities
in an unspecified amount.
On September 1, 1995, the Court denied the Company's motions for
summary judgment and decertification of the class of 107 cities in
this case. Trial has been set for February 1996.
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.
C. Coastal League Litigation
On October 13, 1995, the League for Coastal Protection (Coastal
League) filed a lawsuit in San Francisco County Superior Court against
the Company and its consultant, Tenera, Inc., alleging violations of
the California Business and Professions Code in connection with a 1988
study of the cooling water intake system (1988 Study) at the Company's
Diablo Canyon Nuclear Power Plant (Diablo Canyon). The 1988 Study is
also the subject of an investigation by the California Attorney
General, as described in Item D below. The Coastal League alleges
that the Company and its consultant violated the law by making
misrepresentations in connection with the 1988 Study. The Coastal
League seeks an unspecified amount of damages related to restitution
or disgorgement of improper or excessive profits, punitive damages,
injunctive relief, and attorneys' fees. On October 13, 1995, the
Coastal League also served the Company with a notice that it intends
to file a citizens suit under the Federal Clean Water Act alleging
related violations of Diablo Canyon's water discharge permit.
The Company believes that the ultimate outcome of this matter will not
have a significant adverse impact on its financial position or results
of operations.
D. California Attorney General Investigation
In February 1995, the California Attorney General (AG) initiated an
investigation to determine whether the Company and its consultant,
Tenera, Inc., violated the Federal Clean Water Act and the California
Water Code in connection with the 1988 Study of the cooling water
intake system at Diablo Canyon. The AG has issued a subpoena to the
Company seeking documents and has indicated that he may seek to
interview Company employees in connection with this investigation.
The AG has not determined whether any violation of law has occurred
and has not determined whether it will initiate legal proceedings
against the Company arising out of this investigation. If a legal
action is initiated, the Company could be subject to fines and
penalties which could exceed $100,000, but it cannot be determined
with any certainty at present whether a fine will ultimately be
imposed or what the amount of any such fine would be.
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
-----------------
A. Helms Pumped Storage Plant
Helms Pumped Storage Plant (Helms), a three-unit hydroelectric
combined generating and pumped storage facility, completion of which
was delayed due to a water conduit rupture in 1982 and various start-
up problems related to the plant's generators, became commercially
operable in 1984. As a result of the damage caused by the rupture and
the delay in the operational date, the Company incurred additional
costs which are currently excluded from rate base and lost revenues
during the period while the plant was under repair. In 1991, the
Company filed an application with the CPUC for rate recovery of the
remaining unrecovered Helms costs (excluding costs related to the
conduit rupture), the associated revenue requirement on such costs
since 1984 and lost revenues during the period while the plant was
under repair. In October 1994, the Company submitted for CPUC
approval a settlement (Helms Settlement) with the CPUC's Division of
Ratepayer Advocates (DRA) regarding the recovery of Helms costs not
currently in rate base (excluding costs related to the conduit
rupture) and prior-year revenue requirements related to these costs.
The settlement provides for recovery of substantially all of the
remaining net unrecovered costs and revenues.
On September 22, 1995, the CPUC issued for comment the proposed
decision of the assigned Administrative Law Judge (ALJ) which denies
approval of the Helms Settlement. The proposed decision finds that
the maximum amount the Company would be entitled to recover under the
prior CPUC decisions is $82 million, while the settlement would
authorize recovery of approximately $98 million. Accordingly, the
proposed decision finds the settlement is not consistent with the law
or in the public interest. The proposed decision directs the Company
to amend its application to include only those costs authorized for
potential recovery as specified by the terms of the proposed decision.
The CPUC may adopt or modify the proposed decision after considering
comments by parties to the case. In its comments, the Company
indicated that the proposed decision fails to construe properly the
prior CPUC decisions which permitted accrual and recovery of interest.
It is the Company's position that had the proposed decision properly
construed prior CPUC orders and included accrued interest, the $82
million figure cited in the proposed decision as potentially eligible
for recovery would have been well above the settlement amount of $98
million. The DRA has filed comments on the proposed decision which
are supportive of the Company's assessment of potentially eligible
costs.
B. Ratios of Earnings to Fixed Charges and Ratios of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
The Company's earnings to fixed charges ratio for the nine months
ended September 30, 1995, was 4.51. The Company's earnings to
combined fixed charges and preferred stock dividends ratio for the
nine months ended September 30, 1995, was 3.99. Statements setting
forth the computation of the foregoing ratios are filed herewith as
Exhibits 12.1 and 12.2 to Registration Statement Nos. 33-62488,
33-64136 and 33-50707.
Item 6. Exhibits and Reports on Form 8-K
---------------------------------
(a) Exhibits:
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K during the third quarter of 1995 and
through the date hereof:
1. July 14, 1995
Item 5. Other Events
A. Gas Restructuring and Settlement Proposal
2. July 20, 1995
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
3. August 17, 1995
Item 5. Other Events
A. 1996 Cost of Capital
4. October 4, 1995
Item 5. Other Events
A. Gas Accord
5. October 19, 1995
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. Holding Company Formation
6. October 26, 1995
Item 5. Other Events
A. Diablo Canyon Outage
7. November 2, 1995
Item 5. Other Events
A. General Rate Case
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
November 13, 1995 GORDON R. SMITH
By________________________________
GORDON R. SMITH
Senior Vice President and Chief
Financial Officer
EXHIBIT INDEX
Exhibit
Number Exhibit
- -------- --------------------------------------------------
11 Computation of Earnings Per Common Share
12.1 Computation of Ratios of Earnings to Fixed Charges
12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
27 Financial Data Schedule
<TABLE>
EXHIBIT 11
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
(unaudited)
<CAPTION>
- ---------------------------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
-------------------- ---------------------
(in thousands, except per share amounts) 1995 1994 1995 1994
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
PRIMARY EPS
Net income $377,593 $425,633 $1,111,800 $903,950
Less: preferred dividend requirement 15,901 14,494 44,889 43,314
-------- -------- ---------- ---------
Net income for calculating primary EPS $361,692 $411,139 $1,066,911 $860,636
======== ======== ========== =========
Average common shares outstanding as shown
in the statement of consolidated income 421,578 430,439 426,064 429,584
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) 179 443 117 572
-------- -------- ---------- ---------
Average common shares outstanding as
adjusted 421,757 430,882 426,181 430,156
======== ======== ========== =========
Primary EPS $ .85 $ .95 $ 2.50 $ 2.00
======== ======== ========== =========
FULLY DILUTED EPS (1)
Net income $377,593 $425,633 $1,111,800 $903,950
Less: preferred dividend requirement 15,901 14,494 44,889 43,314
-------- -------- ---------- ---------
Net income for calculating fully diluted EPS $361,692 $411,139 $1,066,911 $860,636
======== ======== ========== =========
Average common shares outstanding as shown
in the statement of consolidated income 421,578 430,439 426,064 429,584
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) 204 443 204 572
-------- -------- ---------- ---------
Average common shares outstanding as
adjusted 421,782 430,882 426,268 430,156
======== ======== ========== =========
Fully diluted EPS $ .85 $ .95 $ 2.50 $ 2.00
======== ======== ========== =========
- ---------------------------------------------------------------------------------------------
<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>
- ---------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) Sept. 30, 1995 1994 1993 1992 1991 1990
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $1,111,800 $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 830 (2,764) 6,895 (3,349) 26,671 (2,799)
Income tax expense 783,735 836,767 901,890 895,126 851,534 881,647
Net fixed charges 538,396 730,965 821,166 802,198 776,682 812,568
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $2,434,761 $2,572,418 $2,795,446 $2,864,556 $2,681,279 $2,678,586
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-term
debt $ 478,571 $ 651,912 $ 731,610 $ 739,279 $ 697,185 $ 699,849
Interest on short-term
borrowings 57,485 77,295 87,819 61,182 77,760 110,982
Interest on capital
leases 1,833 1,758 1,737 1,737 1,737 1,737
Capitalized Interest 528 2,660 46,055 6,511 6,107 7,214
Pretax earnings required to
cover the preferred stock
dividend requirements of
majority owned subsidiaries 864 - - - - -
-------- ---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $ 539,281 $ 733,625 $ 867,221 $ 808,709 $ 782,789 $ 819,782
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 4.51 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 and 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>
- ---------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) Sept. 30, 1995 1994 1993 1992 1991 1990
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $1,111,800 $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 830 (2,764) 6,895 (3,349) 26,671 (2,799)
Income tax expense 783,735 836,767 901,890 895,126 851,534 881,647
Net fixed charges 538,396 730,965 821,166 802,198 776,682 812,568
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $2,434,761 $2,572,418 $2,795,446 $2,864,556 $2,681,279 $2,678,586
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 478,571 $ 651,912 $ 731,610 $ 739,279 $ 697,185 $ 699,849
Interest on short-
term borrowings 57,485 77,295 87,819 61,182 77,760 110,982
Interest on capital
leases 1,833 1,758 1,737 1,737 1,737 1,737
Capitalized Interest 528 2,660 46,055 6,511 6,107 7,214
Pretax earnings required to
cover the preferred stock
dividend requirements of
majority owned subsidiaries 864 - - - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 539,281 733,625 867,221 808,709 782,789 819,782
---------- ---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 8,515 4,672 4,814 5,136 5,136 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 62,015 96,039 108,937 130,147 154,404 175,881
---------- ---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 70,530 100,711 113,751 135,283 159,540 181,017
---------- ---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and
Preferred Stock
Dividends $ 609,811 $ 834,336 $ 980,972 $ 943,992 $ 942,329 $1,000,799
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed
Charges and Preferred
Stock Dividends 3.99 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 and 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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-END> SEP-30-1995
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 18,990,175
<OTHER-PROPERTY-AND-INVEST> 1,698,017
<TOTAL-CURRENT-ASSETS> 3,385,661
<TOTAL-DEFERRED-CHARGES> 2,807,077
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 26,880,930
<COMMON> 2,091,930
<CAPITAL-SURPLUS-PAID-IN> 3,740,433
<RETAINED-EARNINGS> 2,879,978
<TOTAL-COMMON-STOCKHOLDERS-EQ> 8,712,341
137,500
582,995
<LONG-TERM-DEBT-NET> 8,207,071
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 106,304
<LONG-TERM-DEBT-CURRENT-PORT> 444,715
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 8,690,004
<TOT-CAPITALIZATION-AND-LIAB> 26,880,930
<GROSS-OPERATING-REVENUE> 7,400,304
<INCOME-TAX-EXPENSE> 866,709
<OTHER-OPERATING-EXPENSES> 5,039,132
<TOTAL-OPERATING-EXPENSES> 5,905,841
<OPERATING-INCOME-LOSS> 1,494,463
<OTHER-INCOME-NET> 127,235
<INCOME-BEFORE-INTEREST-EXPEN> 1,621,698
<TOTAL-INTEREST-EXPENSE> 509,898
<NET-INCOME> 1,111,800
44,889
<EARNINGS-AVAILABLE-FOR-COMM> 1,066,911
<COMMON-STOCK-DIVIDENDS> 627,048
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 2,756,541
<EPS-PRIMARY> 2.50
<EPS-DILUTED> 2.50
</TABLE>
