FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
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(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 1996
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File No. 1-2348
PACIFIC GAS AND ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
California 94-0742640
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(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
77 Beale Street, P.O. Box 770000, San Francisco, California 94177
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code:(415) 973-7000
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding twelve months
(or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements
for the past 90 days.
Yes X No
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Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Class Outstanding at July 31, 1996
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Common Stock, $5 par value 415,749,797 shares
Form 10-Q
TABLE OF CONTENTS
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PART I. FINANCIAL INFORMATION Page
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Item 1. Consolidated Financial Statements and Notes
Statement of Consolidated Income................... 1
Consolidated Balance Sheet......................... 2
Statement of Consolidated Cash Flows............... 4
Note 1: General
Basis of Presentation................... 5
Note 2: Electric Industry Restructuring........... 5
Note 3: Natural Gas Matters
Gas Reasonableness Proceedings.......... 11
PGT/PG&E Pipeline Expansion Project..... 12
Transportation Commitments.............. 13
Note 4: Diablo Canyon............................. 15
Note 5: Contingencies
Nuclear Insurance....................... 15
Environmental Remediation............... 16
Helms Pumped Storage Plant.............. 17
Legal Matters........................... 17
Note 6: Company Obligated Mandatorily
Redeemable Preferred Securities
of Subsidiary Trust Holding Solely
PG&E Subordinated Debentures.............. 18
Item 2. Management's Discussion and Analysis of Consolidated
Results of Operations and Financial Condition
Electric Industry Restructuring.................... 19
Gas Industry Restructuring......................... 23
Holding Company Structure.......................... 24
Utility Revenue Matters............................ 25
Results of Operations.............................. 27
Earnings Per Common Share........................ 28
Common Stock Dividend............................ 28
Operating Revenues............................... 29
Operating Expenses............................... 29
Liquidity and Capital Resources
Sources of Capital............................... 29
Acquisition...................................... 30
Environmental Remediation........................ 30
Legal Matters.................................... 30
Accounting for Decommissioning Expense........... 30
PART II. OTHER INFORMATION
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Item 1. Legal Proceedings
Time-of-Use Meter/Customer
Notification Litigation......................... 31
Item 5. Other Information
Ratios of Earnings to Fixed Charges and
Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends............ 31
Item 6. Exhibits and Reports on Form 8-K..................... 32
SIGNATURE...................................................... 33
PART 1. FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
---------------------------------
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
(in thousands, --------------------------- --------------------------
except per share amounts) 1996 1995 1996 1995
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric utility $1,660,867 $1,894,667 $3,309,469 $3,591,453
Gas utility 451,511 506,550 1,020,322 1,050,645
Diversified operations 26,288 47,424 57,643 114,790
---------- ---------- ---------- ----------
Total operating revenues 2,138,666 2,448,641 4,387,434 4,756,888
---------- ---------- ---------- ----------
OPERATING EXPENSES
Cost of electric energy 530,792 518,005 997,786 922,728
Cost of gas 67,151 83,349 255,288 186,912
Maintenance and other operating 525,058 391,929 981,532 813,883
Depreciation and decommissioning 303,382 344,293 606,329 696,476
Administrative and general 346,762 214,592 526,141 475,713
Workforce reduction cost - - - (18,195)
Property and other taxes 77,146 76,103 158,589 149,972
---------- ---------- ---------- ----------
Total operating expenses 1,850,291 1,628,271 3,525,665 3,227,489
---------- ---------- ---------- ----------
OPERATING INCOME 288,375 820,370 861,769 1,529,399
---------- ---------- ---------- ----------
OTHER INCOME AND (INCOME DEDUCTIONS)
Interest income 21,348 17,619 45,691 32,945
Allowance for equity funds
used during construction 3,321 6,462 6,078 12,100
Other--net 7,973 19,888 13,655 17,420
---------- ---------- ---------- ----------
Total other income and
(income deductions) 32,642 43,969 65,424 62,465
---------- ---------- ---------- ----------
INCOME BEFORE INTEREST EXPENSE 321,017 864,339 927,193 1,591,864
---------- ---------- ---------- ----------
INTEREST EXPENSE
Interest on long-term debt 149,324 162,423 302,491 324,572
Other interest charges 14,059 13,561 36,377 28,337
Allowance for borrowed funds
used during construction (1,899) (3,207) (3,456) (6,083)
---------- ---------- ---------- ----------
Net interest expense 161,484 172,777 335,412 346,826
---------- ---------- ---------- ----------
PRETAX INCOME 159,533 691,562 591,781 1,245,038
---------- ---------- ---------- ----------
INCOME TAXES 47,753 286,042 219,297 510,831
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NET INCOME 111,780 405,520 372,484 734,207
Preferred dividend requirement
and redemption premium 8,278 14,494 16,556 28,988
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EARNINGS AVAILABLE FOR
COMMON STOCK $ 103,502 $ 391,026 $ 355,928 $ 705,219
========== ========== ========== ==========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING 415,125 426,621 414,738 428,344
EARNINGS PER COMMON SHARE $.25 $.92 $ .86 $1.65
DIVIDENDS DECLARED PER COMMON SHARE $.49 $.49 $ .98 $ .98
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<FN>
The accompanying Notes to Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
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June 30, December 31,
(in thousands) 1996 1995
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<S> <C> <C>
ASSETS
PLANT IN SERVICE
Electric
Nonnuclear $17,928,412 $17,513,830
Diablo Canyon 6,680,862 6,646,853
Gas 7,900,198 7,732,681
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Total plant in service (at original cost) 32,509,472 31,893,364
Accumulated depreciation and decommissioning (13,953,587) (13,308,596)
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Net plant in service 18,555,885 18,584,768
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CONSTRUCTION WORK IN PROGRESS 239,679 333,263
OTHER NONCURRENT ASSETS
Nuclear decommissioning funds 816,459 769,829
Investments in nonregulated projects 834,749 869,674
Other assets 128,957 130,128
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Total other noncurrent assets 1,780,165 1,769,631
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CURRENT ASSETS
Cash and cash equivalents 137,457 734,295
Accounts receivable
Customers 1,174,774 1,238,549
Other 33,449 65,907
Allowance for uncollectible accounts (37,552) (35,520)
Regulatory balancing accounts receivable 728,128 746,344
Inventories
Materials and supplies 178,018 181,763
Gas stored underground 127,609 146,499
Fuel oil 30,200 40,756
Nuclear fuel 173,677 175,957
Prepayments 26,644 47,025
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Total current assets 2,572,404 3,341,575
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DEFERRED CHARGES
Income tax-related deferred charges 1,051,458 1,079,673
Diablo Canyon costs 375,965 382,445
Unamortized loss net of gain on reacquired debt 384,969 392,116
Workers' compensation and disability claims recoverable 287,812 297,266
Other 509,764 669,553
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Total deferred charges 2,609,968 2,821,053
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TOTAL ASSETS $25,758,101 $26,850,290
=========== ===========
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<FN>
(continued on next page)
</TABLE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
June 30, December 31,
(in thousands) 1996 1995
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<S> <C> <C>
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock $ 2,064,488 $ 2,070,128
Additional paid-in capital 3,753,964 3,716,322
Reinvested earnings 2,700,704 2,812,683
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Total common stock equity 8,519,156 8,599,133
Preferred stock without mandatory redemption provisions 402,056 402,056
Preferred stock with mandatory redemption provisions 137,500 137,500
Company obligated mandatorily redeemable preferred
securities of subsidiary trust holding solely
PG&E subordinated debentures 300,000 300,000
Long-term debt 7,923,496 8,048,546
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Total capitalization 17,282,208 17,487,235
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OTHER NONCURRENT LIABILITIES
Customer advances for construction 133,649 146,191
Workers' compensation and disability claims 271,400 271,000
Other 724,879 815,960
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Total other noncurrent liabilities 1,129,928 1,233,151
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CURRENT LIABILITIES
Short-term borrowings 56,073 829,947
Long-term debt 221,133 304,204
Accounts payable
Trade creditors 360,671 413,972
Other 369,748 387,747
Accrued taxes 403,323 274,093
Deferred income taxes 169,360 227,782
Interest payable 68,889 70,179
Dividends payable 211,445 205,467
Other 605,463 504,973
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Total current liabilities 2,466,105 3,218,364
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DEFERRED CREDITS
Deferred income taxes 3,950,144 3,933,765
Deferred tax credits 387,420 393,255
Noncurrent balancing account liabilities 211,292 185,647
Other 331,004 398,873
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Total deferred credits 4,879,860 4,911,540
CONTINGENCIES (Notes 2, 3 and 5)
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TOTAL CAPITALIZATION AND LIABILITIES $25,758,101 $26,850,290
=========== ===========
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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>
- --------------------------------------------------------------------------------------------
Six months ended June 30,
------------------------
(in thousands) 1996 1995
- --------------------------------------------------------------------------------------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 372,484 $ 734,207
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and decommissioning 606,329 696,476
Amortization 44,774 69,189
Gain on sale of DALEN - (13,107)
Deferred income taxes and tax credits--net (18,532) (134,184)
Allowance for equity funds used during construction (6,078) (12,100)
Other deferred charges 75,301 40,427
Other noncurrent liabilities (22,223) (24,495)
Noncurrent balancing account liabilities and
other deferred credits (42,224) (72,689)
Net effect of changes in operating assets
and liabilities
Accounts receivable 98,265 185,252
Regulatory balancing accounts receivable 18,216 286,443
Inventories 33,191 31,738
Accounts payable (71,300) (85,434)
Accrued taxes 129,230 189,768
Other working capital 119,581 (56,774)
Other-net 40,987 33,851
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Net cash provided by operating activities 1,378,001 1,868,568
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CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (509,653) (399,033)
Allowance for borrowed funds used during construction (3,456) (6,083)
Nonregulated projects 11,596 (59,767)
Proceeds from sale of DALEN - 340,000
Other--net (40,644) (123,177)
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Net cash used by investing activities (542,157) (248,060)
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CASH FLOWS FROM FINANCING ACTIVITIES
Common stock issued 113,290 92,315
Common stock repurchased (135,036) (267,799)
Long-term debt issued 983,944 567,160
Long-term debt matured, redeemed or repurchased (1,196,269) (957,583)
Short-term debt redeemed--net (773,874) (314,685)
Dividends paid (422,994) (451,082)
Other--net (1,743) (9,457)
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Net cash used by financing activities (1,432,682) (1,341,131)
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NET CHANGE IN CASH AND CASH EQUIVALENTS (596,838) 279,377
CASH AND CASH EQUIVALENTS AT JANUARY 1 734,295 136,900
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CASH AND CASH EQUIVALENTS AT JUNE 30 $ 137,457 $ 416,277
========== ==========
Supplemental disclosures of cash flow information
Cash paid for
Interest (net of amounts capitalized) $ 318,292 $ 330,640
Income taxes 106,119 459,028
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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 1995 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 1996 presentation. Results of operations
for interim periods are not necessarily indicative of results to be
expected for a full year.
NOTE 2: Electric Industry Restructuring
- ----------------------------------------
On December 20, 1995, the California Public Utilities Commission (CPUC)
issued a decision calling for the restructuring of California's
electric industry. The CPUC's goal is to provide a structure that will
ultimately allow California consumers to choose among competing
suppliers of electricity. In summary, the decision would (1)
simultaneously create a wholesale power pool, or Exchange, and allow
direct access for certain customers to contract directly with electric
generation providers beginning in 1998 with all customers phased in
within five years; (2) establish an Independent System Operator (ISO)
to manage and control the transmission system; (3) provide recovery of
utilities' transition costs (costs which are above-market and could not
be recovered under market-based pricing) through a surcharge, or
competition transition charge (CTC), to be imposed on all customers;
(4) allow investor-owned utilities to continue to provide distribution,
generation and procurement functions for those customers choosing to
take bundled service from the utilities, all of which would be
regulated under performance-based ratemaking (PBR); and (5) provide
incentives to encourage voluntary divestiture of at least 50 percent of
utilities' fossil fuel generation assets. The decision and subsequent
CPUC rulings and workshops have set out an ambitious schedule for
various implementation filings and comments through mid-1997.
To prepare for competition in electric generation resulting from the
CPUC's restructuring decision, PG&E has filed regulatory applications
and proposals in three key areas: implementation, ratemaking and CTC
recovery. In addition, in June 1996, PG&E entered into a Restructuring
Rate Settlement with several parties representing consumers, labor and
independent electricity producers. This Settlement endorses the
Company's proposed modification of the Diablo Canyon Nuclear Power
Plant (Diablo Canyon) rate case settlement as modified in 1995 (Diablo
Settlement), establishment of a customer electric rate freeze, and
certain principles governing restructuring of PG&E's electric business
which will be reflected in PG&E's filings as summarized below. In
addition, at the California Legislature, a two-house conference
committee on Electric Industry Restructuring has been holding hearings
and considering legislation which would resolve various issues relating
to restructuring of the electric industry. To date, the committee has
not adopted any legislative proposals, and the current legislative
session ends August 31, 1996. The Company cannot predict whether
legislation will in fact be adopted before the end of the legislative
session or the substance of any legislation that may be adopted.
IMPLEMENTATION: In April 1996, PG&E, San Diego Gas and Electric
Company (SDG&E) and Southern California Edison Company (SCE) filed
joint ISO and Exchange applications with the Federal Energy Regulatory
Commission (FERC) and the CPUC. These applications requested
authorization to transfer operational control (but not ownership) of
certain jurisdictional transmission facilities to the ISO and to sell
electric energy at market-based rates using the Exchange.
In August 1996, the CPUC conditionally approved a joint application by
PG&E, SDG&E and SCE which establishes two tax-exempt trusts for the
purpose of overseeing the costs associated with the development of the
ISO and Exchange. These costs are estimated to range between $200 and
$300 million and would be financed through bank loans to the trust
supported by guarantees by PG&E and the other utilities. PG&E would
guarantee a maximum of $112.5 million of such costs.
In March 1996, PG&E filed comments with the CPUC indicating that it is
willing to proceed with voluntary divestiture of at least 50 percent of
its fossil fuel generation assets, as long as CTC recovery is
satisfactorily resolved. In its filing, PG&E described various options
for divestiture, including spinning assets off to a new unaffiliated
corporate entity, selling assets on the open market, negotiating with
individual potential buyers in special circumstances, leasing
facilities and/or selling assets to employees through an employee stock
ownership plan. PG&E will also evaluate the economic feasibility and
desirability of divesting additional nonnuclear generating assets.
PG&E is currently evaluating the marketplace, including identifying
plants that might be divested, and identifying the form divestiture
might take and when it might occur.
In March 1996, PG&E filed comments with the CPUC on the feasibility,
timing and consequences of a corporate restructuring to separate PG&E's
operations and assets between the generation, transmission and
distribution functions, indicating that, for the time being, it sees no
obvious benefits from separating its generation, transmission and
distribution functions into separate corporate subsidiaries. However,
PG&E believes it may be appropriate in the future to hold any
generation it retains in a separate corporate entity and that such
segregation of assets would be consistent with the holding company
structure it proposed in a filing with the CPUC in October 1995.
RATEMAKING: In July 1996, consistent with the CPUC's restructuring
decision, PG&E submitted an application proposing to establish a PBR
mechanism for a portion of its electric generation services. Key
elements of PG&E's proposed generation PBR include the following:
1) PG&E proposes a combined PBR recovery mechanism for its
hydroelectric and geothermal generating unit costs. The proposed
mechanism consists of a base revenue amount that is indexed to account
for inflation less a productivity offset and shared earnings.
Adjustments are made to account for fuel costs, performance standards
and extraordinary costs or savings. Implementation of the
hydroelectric/geothermal PBR would begin on January 1, 1998. If PG&E's
proposal to modify Diablo Canyon pricing and implement a customer
electric rate freeze is adopted, the PBR will terminate by the end of
2001, at which time all generation will be priced at market levels.
2) For all fossil generation units, PG&E proposes that after January
1, 1998, sunk costs be recovered directly through the CTC component of
rates, consistent with the CPUC's restructuring decision.
3) PG&E proposes that all fixed and variable operating costs for its
fossil generation units would be recovered either through revenues from
sales through the Exchange or through contracts with the ISO for
services provided to maintain reliability of the transmission system.
Also in July 1996, PG&E submitted a preliminary unbundling proposal to
the CPUC relating to the separation of electric base revenues and the
costs that underlie them into five basic components: generation, CTC,
transmission, distribution, and public purpose programs. PG&E's formal
unbundling application will be filed by November 15, 1996, and will
incorporate any resolution at the FERC regarding the separation between
distribution and transmission functions.
COMPETITION TRANSITION CHARGE RECOVERY: In August 1996, PG&E submitted
its sunk cost application to the CPUC which identifies and values, to
the extent possible at this time, nonnuclear generation-related sunk
costs that will be eligible for recovery through the CTC to be
implemented on January 1, 1998. Sunk costs, defined in the filing as
costs that are fixed and unavoidable, are just one component of the
transition costs eligible for recovery through the CTC. Other such
components will be identified in a separate application to be made on
August 30, 1996. Sunk costs include costs incurred in the past that
are currently included in rates, such as the original costs of
generation facilities, net of accumulated depreciation, and regulatory
assets. PG&E indicated that the value of these sunk costs as of
December 31, 1995, was $4.4 billion. Sunk costs also include costs
that will be incurred in the future, such as fossil decommissioning
costs. These costs are estimated to be $1.8 billion, resulting in
total estimated sunk costs of $6.2 billion. The amounts in the sunk
cost application may change to reflect changes and modifications made
in other restructuring-related CPUC and FERC filings.
PG&E's sunk cost application notes that certain future sunk costs have
been excluded from these estimates consistent with PG&E's Restructuring
Rate Settlement. If these costs were included in PG&E's sunk cost
estimates, PG&E's aggregate sunk costs would increase to $6.8 billion.
In April 1996, the CPUC granted PG&E's emergency motion to establish an
interim CTC procedure applicable to certain departing electric retail
customers. This rate procedure will remain in effect until the CPUC
adopts and implements a final CTC mechanism, which is expected to be
effective January 1, 1998. At that time, amounts paid on an interim
basis will be subject to true up to reflect the CPUC's final CTC
methodology.
MODIFICATION OF DIABLO SETTLEMENT AND RATE FREEZE: In March 1996, PG&E
filed an application with the CPUC seeking approval to modify the
Diablo Settlement, as discussed in Note 4, contingent upon the adoption
of a five-year customer electric rate freeze, effective January 1,
1997. The application would reduce the amount of Diablo Canyon
transition costs by $4 billion (net present value), at an assumed
marked price of $.025, compared to transition costs that would arise
under existing Diablo Canyon prices, while recovering remaining Diablo
Canyon and other uneconomic utility generation assets by no later than
the end of 2001. PG&E's application would result in the termination of
the Diablo Settlement by the end of 2001, at which time Diablo Canyon's
generation may be priced at market levels consistent with the goals of
the CPUC's restructuring decision.
PG&E proposes that the current pricing of Diablo Canyon generation, as
set forth in the Diablo Settlement, be replaced by a new pricing
arrangement. Under this approach, the current Diablo Canyon fixed
price would be replaced by a sunk cost revenue requirement consisting
of PG&E's remaining sunk costs in Diablo Canyon at December 31, 1996,
depreciated over a five-year period and subject to a reduced return on
common equity equal to 6.77 percent. Diablo Canyon sunk costs include
net plant, working capital and regulatory assets, all net of deferred
taxes. The sunk cost revenue requirement would be recovered without
reference to Diablo Canyon's performance, unless the plant were shut
down for nine months or more.
The escalating component of current Diablo Canyon prices would be
replaced by a performance-based Incremental Cost Incentive Price (ICIP)
for recovery of Diablo Canyon's variable costs and future capital
additions. Under the ICIP, the variable costs and incremental capital
additions are recovered under a pre-set price per kilowatt-hour (kWh)
of plant output based on an initial forecast of such costs and output.
The 2016 termination date in the Diablo Settlement would be changed to
December 31, 2001, and related abandonment payment provisions in the
Diablo Settlement would be replaced with closure cost recovery
provisions, under which PG&E would be entitled to recover a percentage
of its annual operating and maintenance and administrative and general
costs for a limited period of years following permanent plant closure.
PG&E's continued recovery of the sunk cost revenue requirement would be
subject to CPUC evaluation if Diablo Canyon is shut down for nine
months or more prior to such time as transition costs are fully
recovered. After such time as transition costs are fully recovered,
there would be no restrictions on Diablo Canyon's operations, to which
customers it could sell and at what prices, terms and conditions, but
50 percent of any after-tax earnings available for common equity after
such time would be allocated to ratepayers.
Certain fixed or safety-related costs, such as decommissioning costs,
would continue to be recovered in PG&E's base rates without reference
to Diablo Canyon's performance. At PG&E's option, recovery of
estimated decommissioning costs could be accelerated under the customer
electric rate freeze over the same depreciation period as Diablo
Canyon's sunk costs.
In conjunction with these modifications to the Diablo Settlement,
PG&E's application proposes that the CPUC adopt a customer electric
rate freeze at 1996 levels through the end of 2001, in order to permit
PG&E to accelerate capital recovery of its other utility generation and
associated regulatory assets through 2001. PG&E would be at risk for
completing recovery of PG&E's above-market utility generation-related
investments, including Diablo Canyon, and related regulatory assets by
the end of 2001.
PG&E indicated that adoption of its customer electric rate freeze
proposal is linked inextricably with the proposal to modify Diablo
Canyon pricing. In the event that the CPUC is unable to adopt the
proposed customer electric rate freeze, PG&E would withdraw its
proposal to modify Diablo Canyon pricing and instead would propose an
alternative modification of Diablo Canyon pricing.
In June 1996, a CPUC administrative law judge (ALJ) issued a ruling
establishing a procedural schedule for PG&E's Diablo Canyon/rate freeze
proposal. The ruling calls for a Division of Ratepayer Advocates (DRA)
report in August and public hearings in October 1996. A proposed
decision is scheduled for February 1997, with a final decision expected
in late March 1997.
Financial Impact of the Electric Industry Restructuring: In response
to a request from the California Legislative Conference Committee on
Electric Industry Restructuring, PG&E estimated its transition costs
expected to be recovered through the CTC under the restructuring
decision. The estimates of transition costs were based on Diablo
Canyon revenue requirements, cost recovery of power purchase
obligations and generation related regulatory assets, and net cash
flows for nonnuclear generation plants. To provide a range of possible
transition costs, the estimates used market price assumptions of $.035
and $.025 per kWh at January 1, 1996, and an annual escalation rate of
3.2 percent. These market prices do not represent a forecast of
expected market prices. Factors that could impact market prices
include changes in gas prices, changes in inflation rates, levels of
new technology costs and the potential oversupply of generation within
the market.
Based on PG&E's proposal to modify the Diablo Settlement and implement
a customer electric rate freeze, the transition costs of PG&E's owned
generation assets and power purchase obligations were estimated
to be $10.5 billion to $14.0 billion (net present value at January 1998) at
assumed market prices of $.035 and $.025 per kWh. PG&E's proposal to
modify the Diablo Settlement and implement a customer electric rate
freeze accelerates the transition cost recovery period to January 1997
through December 2001 and reduces Diablo Canyon's estimated transition
costs by $3.0 billion to $4.0 billion (net present value) at the
assumed market prices noted above, as compared to transition costs that
would arise under the existing Diablo Settlement. Based on the
existing Diablo Settlement, the net present value at January 1998 of
transition costs for Diablo Canyon were estimated to be $8.1 billion
to $9.6 billion at the assumed market prices noted above. Any forecast of
transition costs is inextricably tied to the assumptions made at the
time of the analysis. The actual amounts of transition costs may
differ materially from those indicated above and will depend on the
costs authorized for recovery, the actual market prices of electricity
in the future and any market valuations of PG&E's generation assets. On
August 30, 1996, PG&E will file its CTC application with the CPUC, which
application will identify all transition costs eligible for recovery through
the CTC.
The CPUC's restructuring decision limits recovery of CTC to an amount
that does not increase customers' aggregate rates above those in effect
on January 1, 1996. The proposal to modify the Diablo Settlement
offers substantial reductions in post-2001 performance-based revenues
in exchange for a commitment to freeze customer electric rates through
2001 to allow accelerated collection of utility generation-related CTC.
Recent CPUC decisions effective on January 1, 1996, including PG&E's
1996 General Rate Case (GRC), have resulted in an average electric
system rate of $.099 per kWh. PG&E believes that the revenues
generated under its proposed customer electric rate freeze would be
adequate to recover its above-market generation assets by the end of
2001. However, PG&E's ability to recover its transition costs will be
dependent on several factors, including: (1) the aggregate amount of
PG&E's transition costs, which in turn depends on a number of factors,
including the expected market value of a portion of its generation
plants, future sales levels, fuel and operating costs and the market
price of electricity; (2) maintaining electric rates at 1996 levels;
and (3) PG&E's ability to continue to collect CTC for the duration of
the recovery period.
The proposal to modify the Diablo Settlement would significantly reduce
the level of PG&E's CTC by reducing the common equity returns on the
Diablo Canyon plant investment to 6.77 percent and accelerating the
capital recovery of the plant and other utility generation-related
assets. In addition, the proposal would also limit recovery of most
utility generation-related CTC to amounts collected through 2001.
The Company currently accounts for the economic effects of regulation
in accordance with the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation," which allows the Company to capitalize certain costs,
that would otherwise have been expensed, as regulatory assets. In
addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of," requires that
regulatory assets be written off when they are no longer probable of
recovery and that impairment losses be recorded for portions of long-
lived assets that are no longer probable of recovery.
When electric generation rates are no longer based on cost of service,
as ultimately contemplated under the CPUC's restructuring decision,
PG&E would discontinue application of SFAS No. 71 for the electric
generation portion of its business. As a result, all applicable
electric generation-related regulatory assets and other transition
costs determined to be probable of CTC recovery would be a regulatory
asset collected through cost-of-service based customer rates and
subject to the provisions to SFAS No. 71. In addition, the CTC account
and electric generation assets will be subject to the criteria of SFAS
No. 121. As a result of applying the provisions of SFAS No. 71, PG&E
had accumulated approximately $1.5 billion of regulatory assets
attributable to electric generation at June 30, 1996. The net
investment in Diablo Canyon and the remaining PG&E-owned generation
assets, including an allocation of common plant, was approximately $4.8
billion and $2.8 billion, respectively, at June 30, 1996. (The above
amounts could vary depending on allocation methods used.) PG&E's
transmission and distribution businesses are expected to remain under
the provisions of SFAS No. 71.
Due to the expected transition cost recovery as provided in the CPUC's
restructuring decision and in PG&E's Diablo Canyon pricing/customer
electric rate freeze proposal, PG&E does not anticipate a material loss
from the discontinuance of SFAS No. 71 or an impairment loss on its
investment in generation assets due to electric industry restructuring.
However, the Company cannot predict the ultimate outcome of the ongoing
changes that are taking place in the electric utility industry or
predict whether such outcome will have a material adverse impact on its
financial position or results of operations. Should final implementing
regulations or any legislation that may be adopted differ significantly
from the CPUC's restructuring decision or PG&E's Diablo Canyon
pricing/customer electric rate freeze proposal, or should full recovery
of generation assets and obligations not be achieved due to changing
costs or limitations imposed by the market or should a CPUC ordered
customer electric rate reduction occur, a material loss could occur.
NOTE 3: Natural Gas Matters
- ----------------------------
Gas Reasonableness Proceedings:
- ------------------------------
Recovery of gas costs through PG&E'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 1994, the CPUC issued a decision which ordered a disallowance of
approximately $90 million of gas costs plus accrued interest of
approximately $25 million through 1993 for PG&E's Canadian gas
procurement activities from 1988 through 1990. In March 1996, PG&E
refunded $53 million of the ordered disallowance to ratepayers pursuant
to a CPUC decision in December 1995 on PG&E's Biennial Cost Allocation
Proceeding. PG&E has filed a lawsuit in a federal district court
challenging the CPUC's decision on Canadian gas costs. In 1995, the
federal court denied a motion filed by the CPUC to dismiss the lawsuit.
A number of other reasonableness issues related to PG&E'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 approximately
$79 million and a penalty of $50 million and indicated that it was
considering additional recommendations for pending issues. PG&E and
the DRA have signed a settlement agreement to resolve these issues for
a $67 million refund by PG&E. In August 1996, the CPUC issued a
decision approving the settlement, contingent upon the DRA and PG&E
agreeing to amend the settlement to include an additional $6.5 million,
which represents interest from the date the DRA and PG&E filed the
settlement agreement with the CPUC. The DRA and PG&E must inform the
CPUC of their position in September 1996. If the parties do not agree
to the amendment, the settled issues would be set for hearings.
At June 30, 1996, PG&E had accrued approximately $150 million for the
CPUC's 1988 through 1990 gas reasonableness decision and issues covered
by the settlement agreement described above. The Company believes the
ultimate outcome of these matters will not have a material adverse
impact on its financial position or results of operations.
PGT/PG&E Pipeline Expansion Project (Pipeline Expansion):
- --------------------------------------------------------
In November 1993, the Company placed in service an expansion of its
natural gas transmission system from the Canadian border into
California. The Pipeline Expansion provides additional firm
transportation capacity to Northern and Southern California and the
Pacific Northwest. The total cost of construction is estimated to be
approximately $1.7 billion; $810 million for the PG&E or California
portion (PG&E Pipeline Expansion) and $852 million for the Pacific Gas
Transmission Company (PGT) or interstate portion.
PG&E has filed an application with the CPUC requesting that capital and
operating costs for the PG&E Pipeline Expansion be found reasonable.
In that CPUC proceeding, the DRA recommended that a minimum of $100
million in capital costs be disallowed for recovery in rates while two
intervenors jointly recommended a $237 million disallowance or
reallocation of costs among customers. Evidentiary hearings will be
held in late 1996. Revenues are currently being collected under
interim rates approved by the CPUC, subject to adjustment. At June 30,
1996, PG&E had collected approximately $190 million under such rates.
In January 1996, an ALJ ordered consolidation of the market impact
phase of the PG&E Pipeline Expansion reasonableness proceeding and the
Interstate Transition Cost Surcharge (ITCS) proceeding discussed below.
Evidentiary hearings in this phase of the proceeding were held in April
and May 1996.
An order issued by an ALJ has also reopened the 1993 PG&E Pipeline
Expansion Rate Case to allow reconsideration of issues regarding the
decision to construct the PG&E Pipeline Expansion. Evidentiary
hearings in the reopened proceeding were conducted in June 1996. If
the CPUC were to reverse its previous decision finding PG&E was
reasonable in constructing the PG&E Pipeline Expansion, the ultimate
outcome could have an impact on PG&E's ability to recover its cost for
unused capacity on other pipelines as well as on its own intrastate
facilities.
For the interstate portion of the Pipeline Expansion, PGT included $832
million of capital costs, representing such costs incurred through July
1994, in its 1994 GRC filing with the FERC. No parties contested these
costs and the parties have since filed a proposed settlement of that
rate case with the FERC for approval.
Decisions in these proceedings are expected in 1996 and 1997. The
Company believes the ultimate outcome of these matters will not have a
material adverse impact on its financial position or results of
operations.
Transportation Commitments:
- --------------------------
PG&E has gas transportation service agreements with various Canadian
and interstate pipeline companies. These agreements include provisions
for payment of fixed demand charges for reserving firm capacity on the
pipelines. The total demand charges that PG&E will pay each year may
change due to changes in tariff rates and may be offset to the extent
PG&E can broker or permanently assign any unused capacity.
The following table summarizes the approximate capacity held by PG&E on
various pipelines (excluding PGT) and the related annual demand charges
at June 30, 1996:
Total
Firm Capacity Annual Demand
Pipeline Held Charges Contract
Company (MMcf/d) (in millions) Expiration
- ---------------------- ------------- ------------- ----------
El Paso 1,140 $163 Dec. 1997
Transwestern 200 $ 28 Mar. 2007
NOVA 600 $ 20 Oct. 2001
ANG 600 $ 13 Oct. 2005
As a result of regulatory changes, PG&E no longer procures gas for its
industrial and large commercial (noncore) customers, resulting in a
decrease in PG&E's need for firm transportation capacity for its gas
purchases. PG&E continues to procure gas for its residential and
smaller commercial (core) customers and noncore customers who choose
bundled service (core subscription customers). In order to service
these customers, PG&E holds approximately 600 million cubic feet per
day (MMcf/d) of firm capacity for its core and core subscription
customers on each of the pipelines owned by El Paso Natural Gas Company
(El Paso), NOVA Corporation of Alberta (NOVA) and Alberta Natural Gas
Company Ltd (ANG).
PG&E is continuing its efforts to broker or assign any remaining unused
capacity including that held for its core and core subscription
customers when such capacity is not being used. Due to relatively low
demand for Southwest pipeline capacity, PG&E cannot predict the volume
or price of the capacity on El Paso and Transwestern Pipeline Company
(Transwestern) that will be brokered or assigned.
Substantially all demand charges incurred by PG&E for pipeline
capacity, including charges for capacity formerly used to service
noncore customers which cannot be brokered or which is brokered at a
discount, are eligible for rate recovery, subject to a reasonableness
review. However, certain groups, including the DRA and intervenors,
have challenged the recovery of certain demand charges.
In December 1995, the CPUC issued a decision on the reasonableness of
PG&E's 1992 operations concluding that it was unreasonable for PG&E to
subscribe for transportation capacity with Transwestern. The decision
concluded that PG&E was unable to prove the benefits of such capacity
during 1992 and denied recovery of the $18 million of Transwestern
charges for that year. The decision further orders that costs for the
capacity in subsequent years of the contract, which expires in 2007, be
disallowed unless PG&E can demonstrate that the benefits of the
commitment outweigh the costs. PG&E is seeking rehearing of this
decision.
The recovery of demand charges associated with capacity which was
formerly used to serve PG&E's noncore customers will be decided by the
CPUC in the ITCS proceeding. Pending a final decision in the ITCS
proceeding, the CPUC has approved collection in rates of approximately
one-half of the demand charges for unbrokered or discounted El Paso and
PGT capacity which was formerly used to serve PG&E's noncore customers,
subject to refund.
In October 1995, PG&E presented a proposal, called the Gas Accord, to
numerous parties active in the California gas marketplace, in an effort
to restructure the California gas market. As part of the Gas Accord
negotiations, PG&E is pursuing the resolution of existing regulatory
issues pending in separate CPUC proceedings. Regulatory issues being
negotiated as part of the Gas Accord include PG&E's capacity
commitments with Transwestern, recovery of the costs for unbrokered
capacity commitments under the ITCS mechanism and the reasonableness
proceedings for the PG&E Pipeline Expansion.
In addition to the Gas Accord negotiations, PG&E is proposing to
replace traditional reasonableness proceedings relating to its gas
procurement costs with a core procurement incentive mechanism (CPIM).
The CPIM would allow PG&E to recover its gas costs under a mechanism
through which PG&E would receive benefits or be penalized depending on
whether its actual core procurement costs were within, below or above a
"tolerance band" constructed around a market benchmark.
Based on the current status of the Gas Accord negotiations and
regulatory proceedings, the Company believes the ultimate resolution of
past and future Transwestern costs, the ITCS proceeding and the PG&E
Pipeline Expansion proceedings, either through settlement negotiations
or ongoing proceedings, will not have a material adverse impact on its
financial position or results of operations.
NOTE 4: Diablo Canyon
- ----------------------
In May 1995, the CPUC approved a modification to the pricing provisions
of the Diablo Settlement. Under the modification, the prices for power
produced by Diablo Canyon for 1996 through 1999 are 10.5 cents, 10.0
cents, 9.5 cents and 9.0 cents per kWh, respectively, effective January
1. PG&E has the right to reduce the price below the amount specified.
All other terms and conditions of the Diablo Settlement remain
unchanged. Under the modified pricing, at full operating power each
Diablo Canyon unit would contribute approximately $2.7 million in
revenues per day in 1996.
As discussed in Note 2, in connection with the CPUC's electric
industry restructuring decision, PG&E filed in March 1996, a proposal
for pricing Diablo Canyon generation at market prices and completing
recovery of the investment in Diablo Canyon and terminating the
Diablo Settlement by the end of 2001.
NOTE 5: Contingencies
- ----------------------
Nuclear Insurance:
- -----------------
PG&E is a member of Nuclear Mutual Limited (NML) and Nuclear Electric
Insurance Limited (NEIL). Under these policies, if the nuclear
generating facility of a member utility suffers a property damage loss
or a business interruption loss due to a prolonged accidental outage,
PG&E may be subject to maximum assessments of $26 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.
Federal law requires all utilities with nuclear generating facilities
to share in payment for claims resulting from a nuclear incident and
limits industry liability for third-party claims 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 claims in excess
of $200 million, PG&E 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 records its environmental liabilities when site assessments
and/or remedial actions are probable and a range of reasonably likely
cleanup costs can be estimated. The Company reviews its sites and
measures the liability quarterly, by assessing a range of reasonably
likely costs for each identified site using currently available
information, including existing technology, presently enacted laws and
regulations, experience gained at similar sites and the probable level
of involvement and financial condition of other potentially responsible
parties. These estimates include costs for site investigations,
remediation, operations and maintenance, monitoring and site closure.
Unless there is a probable amount, the Company records the lower end of
this reasonably likely range of costs (classified as other noncurrent
liabilities). 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) or the California Hazardous Substance Account
Act. These sites include former manufactured gas plant sites and sites
used by PG&E for the storage or disposal of materials which may be
determined to present a significant threat to human health or the
environment because of an actual or potential release of hazardous
substances. Under CERCLA, the Company's financial responsibilities may
include remediation of hazardous wastes, even if the Company did not
deposit those wastes on the site.
The overall costs of the hazardous materials and hazardous waste
compliance and remediation activities ultimately undertaken by the
Company are difficult to estimate, and it is reasonably possible that a
change in the estimate will occur in the near term due to uncertainty
concerning the Company's responsibility, changing environmental laws
and regulations, evolving technologies, the nature and extent of
required remediation, the selection of compliance alternatives and the
ultimate outcome of factual investigations. The Company has an accrued
liability at June 30, 1996, of $152 million for hazardous waste
remediation costs at those sites where such costs are probable and
quantifiable. The costs may be as much as $364 million if, among other
things, 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. This upper
limit of the range of costs was estimated using assumptions less
favorable to the Company, among a range of reasonably possible
outcomes. Costs may be higher if the Company is found to be
responsible for cleanup costs at additional sites or identifiable
possible outcomes change.
The Company will seek recovery of prudently incurred hazardous waste
compliance and remediation costs through ratemaking procedures approved
by the CPUC, through insurance and through other recoveries from third
parties. The Company has recorded a regulatory asset at June 30, 1996,
of $132 million for recovery of these costs in future rates. While the
Company has numerous insurance policies that it believes may provide
coverage for some of these liabilities, it does not recognize insurance
or third-party recoveries in its financial statements until they are
realized. The Company believes the ultimate outcome of these matters
will not have a material adverse impact on its financial position or
results of operations.
Helms Pumped Storage Plant (Helms):
- ----------------------------------
Helms is a three-unit hydroelectric combined generating and pumped
storage plant with a net investment of $713 million at June 30, 1996.
The net investment is comprised of the pumped storage facility
(including regulatory assets of $50 million), common plant and
dedicated transmission plant. As part of the 1996 GRC decision issued
in December 1995, the CPUC directed PG&E to perform a cost-
effectiveness study of Helms. In July 1996, PG&E submitted its study,
which concluded that the continued operation of Helms is cost
effective. PG&E recommended that the CPUC take no action as a result
of the study, but address Helms along with other generating plants in
the context of electric industry restructuring.
PG&E is currently unable to predict whether there will be a change in
rate recovery resulting from the study. As with its other
hydroelectric generating plants, the Company expects to seek recovery
of its net investment in Helms through the hydroelectric/geothermal PBR
and CTC mechanisms (see Note 2). The Company believes that the
ultimate outcome of this matter will not have a material adverse impact
on its financial position or results of operations.
Legal Matters:
- -------------
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 PG&E's Hinkley
Compressor Station, as well as punitive damages.
In June 1996, PG&E agreed to settle the plaintiffs' claims for the
aggregate sum of $333 million, of which $50 million had already been
paid. Accordingly, at June 30, 1996, $283 million was included in
other current liabilities. The settlement resulted in a charge of $133
million in the second quarter of 1996.
Cities Franchise Fees Litigation: In 1994, the City of Santa Cruz
filed a class action suit in a state superior court (Court) against
PG&E on behalf of itself and 106 other cities in PG&E's service area.
The complaint alleges that PG&E has underpaid electric franchise fees
to the cities by calculating fees at different rates from other
cities.
In September 1995, the Court certified the class of 107 cities in
this action and approved the City of Santa Cruz as the class
representative. In January and March 1996, the Court made two
rulings against certain plaintiffs effectively eliminating a major
portion of the class action. The Court's rulings do not resolve the
case completely. The plaintiffs appealed both rulings. The trial
has been postponed pending the plaintiffs' appeal.
Should the cities prevail on the issue of franchise fee calculation
methodology, PG&E's annual systemwide city electric franchise fees
could increase by approximately $17 million and damages for alleged
underpayments for the years 1987 to 1995 could be as much as $131
million (exclusive of interest, estimated to be $35 million at June
30, 1996).
If the Court's January and March 1996 rulings become final, PG&E's
annual systemwide city electric franchise fees for the remaining
class member plaintiffs not subject to the Court's rulings could
increase by approximately $5 million and damages for alleged
underpayments for the years 1987 to 1995 could be as much as $35
million (exclusive of interest, estimated to be $9 million at June
30, 1996).
The Company believes that the ultimate outcome of this matter will not
have a material adverse impact on its financial position or results of
operations.
NOTE 6: Company Obligated Mandatorily Redeemable Preferred Securities
- ----------------------------------------------------------------------
of Subsidiary Trust-Holding Solely PG&E Subordinated Debentures:
- ---------------------------------------------------------------
PG&E through its wholly owned subsidiary, PG&E Capital I (Trust), has
outstanding 12 million shares of 7.90% cumulative quarterly income
preferred securities (QUIPS), with an aggregate liquidation value of
$300 million. Concurrent with the issuance of the QUIPS, the Trust
issued to PG&E 371,135 shares of common securities with an aggregate
liquidation value of approximately $9 million. The only assets of the
Trust are deferrable interest subordinated debentures issued by PG&E
with a face value of approximately $309 million, an interest rate of
7.90 percent and a maturity date of 2025.
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) are engaged
principally in the business of supplying electric and natural gas
services. PG&E is a regulated public utility which provides
generation, procurement, transmission and distribution of electricity
and natural gas to customers throughout most of Northern and Central
California. Pacific Gas Transmission Company (PGT), a wholly owned
subsidiary, transports gas from the Canadian border to the California
border and the Pacific Northwest. The Company's operations are
regulated by the California Public Utilities Commission (CPUC), the
Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory
Commission (NRC), among others.
Building on its expertise in the energy industry, the Company is also
expanding its diversified operations, principally through its wholly
owned subsidiary, PG&E Enterprises (Enterprises). Enterprises, through
its subsidiaries and affiliates, develops, owns and operates electric
and gas projects around the world.
The following discussion includes forward-looking statements that
involve a number of risks and uncertainties including but not limited
to the electric and gas industry restructurings and related filings.
Importantly, the ultimate impact of increased competition and the
changing regulatory environment on future results is uncertain but is
expected to cause fundamental changes in the way PG&E conducts its
business and to make earnings more volatile. This outcome and other
matters discussed below may cause future results to differ materially
from historic results or from results or outcomes currently expected or
sought by the Company.
Electric Industry Restructuring:
- -------------------------------
On December 20, 1995, the CPUC issued a decision calling for the
restructuring of California's electric industry. The restructuring
contemplated in the decision would (1) simultaneously create a
wholesale power pool, or Exchange, and allow direct access for certain
customers to contract directly with electric generation providers
beginning, at the latest, on January 1, 1998, with all customers phased
into direct access within five years; (2) establish an Independent
System Operator (ISO) to manage and control the transmission system;
(3) provide recovery of utilities' stranded costs (costs which are
above-market and could not be recovered under market-based pricing)
through a non-bypassable surcharge, or competition transition charge
(CTC), to be imposed on all customers taking retail electric service as
of or after December 20, 1995; and (4) allow investor-owned utilities
to continue to provide distribution, generation and procurement
functions for those customers choosing to take bundled service from the
utilities, all of which would be regulated under performance-based
ratemaking (PBR); and (5) provide incentives to encourage voluntary
divestiture of at least 50 percent of utilities' fossil fuel generation
assets. The decision and subsequent CPUC rulings and workshops have
set out an ambitious schedule for various implementation filings and
comments through mid-1997.
At the federal level, in April 1996, the FERC issued Order 888 which
requires utilities to provide wholesale open access to utility
transmission systems on terms that are comparable to the way utilities
use their own systems. PG&E filed a tariff in compliance with Order
888 in July 1996. PG&E's tariff, which is almost identical to the
final tariff issued by the FERC as part of Order 888, is now available
for service to any party interested in wholesale transmission service
over PG&E's transmission system. In Order 888, the FERC reaffirmed its
intention to permit utilities to recover any legitimate, verifiable and
prudently incurred generation-related costs stranded as a result of
customers taking advantage of wholesale open access orders to meet
their power needs from other sources. The FERC also asserted that it
has jurisdiction over the transmission aspects of retail direct access,
although it reaffirmed its inability to compel retail wheeling.
To prepare for competition in electric generation resulting from the
CPUC's restructuring decision, PG&E has filed regulatory applications
and proposals in three key areas: implementation, ratemaking and CTC
recovery. In addition, in June 1996, PG&E entered into a Restructuring
Rate Settlement with several parties representing consumers, labor and
independent electricity producers. This Settlement endorses the
Company's proposed modification of the existing Diablo Canyon Nuclear
Power Plant (Diablo Canyon) rate case settlement as modified in 1995
(Diablo Settlement), establishment of a customer electric rate freeze
and certain principles governing restructuring of PG&E's electric
business which will be reflected in PG&E's filings. In addition, at
the California Legislature, a two-house conference committee on
Electric Industry Restructuring has been holding hearings and
considering legislation which would resolve various issues relating to
restructuring of the electric industry. To date, the committee has not
adopted any legislative proposals, and the current legislative session
ends August 31, 1996. The Company cannot predict whether legislation
will in fact be adopted before the end of the legislative session or
the substance of any legislation that may be adopted. See Note 2 of
Notes to Consolidated Financial Statements for further discussion of
the electric industry restructuring and significant filings, proposals
and responses to the CPUC's decision.
Financial Impact of the Electric Industry Restructuring: In response
to a request from the California Legislative Conference Committee on
Electric Industry Restructuring, PG&E estimated its transition costs
expected to be recovered through the CTC under the restructuring
decision. The estimates of transition costs were based on Diablo
Canyon revenue requirements, cost recovery of power purchase
obligations and generation related regulatory assets, and net cash
flows for nonnuclear generation plants. To provide a range of possible
transition costs, the estimates used market price assumptions of $.035
and $.025 per kilowatt-hour (kWh) at January 1, 1996, and an annual
escalation rate of 3.2 percent. These market prices do not represent a
forecast of expected market prices. Factors that could impact market
prices include changes in gas prices, changes in inflation rates,
levels of new technology costs and the potential oversupply of
generation within the market.
Based on PG&E's proposal to modify the Diablo Settlement and implement
a customer electric rate freeze, the transition costs of PG&E's owned
generation assets and power purchase obligations were estimated
to be $10.5 billion to $14.0 billion (net present value at January 1998) at
assumed market prices of $.035 and $.025 per kWh. PG&E's proposal to
modify the Diablo Settlement and implement a customer electric rate
freeze accelerates the transition cost recovery period to January 1997
through December 2001 and reduces Diablo Canyon's estimated transition
costs by $3.0 billion to $4.0 billion (net present value) at the
assumed market prices noted above, as compared to transition costs that
would arise under the existing Diablo Settlement. Based on the
existing Diablo Settlement, the net present value at January 1998 of
transition costs for Diablo Canyon were estimated to be $8.1
billion to $9.6 billion at the assumed market prices noted above. Any
forecast of transition costs is inextricably tied to the assumptions made at
the time of the analysis. The actual amounts of transition costs may
differ materially from those indicated above and will depend on the
costs authorized for recovery, the actual market prices of electricity
in the future and any market valuations of PG&E's generation assets. On
August 30, 1996, PG&E will file its CTC application with the CPUC, which
application will identify all transition costs eligible for recovery
through the CTC.
The CPUC's restructuring decision limits recovery of CTC to an amount
that does not increase customers' aggregate rates above those in effect
on January 1, 1996. The proposal to modify the Diablo Settlement
offers substantial reductions in post-2001 performance-based revenues
in exchange for a commitment to freeze customer electric rates through
2001 to allow accelerated collection of utility generation-related CTC.
Recent CPUC decisions effective on January 1, 1996, including PG&E's
1996 General Rate Case (GRC), have resulted in an average electric
system rate of $.099 per kWh. PG&E believes that the revenues
generated under its proposed customer electric rate freeze would be
adequate to recover its above-market generation assets by the end of
2001. However, see Utility Revenue Matters below for a description of
several pending proceedings relating to 1997 revenues. In addition,
PG&E's ability to recover its transition costs will be dependent on
several factors, including: (1) the aggregate amount of PG&E's
transition costs, which in turn depends on a number of factors,
including the expected market value of a portion of its generation
plants, future sales levels, fuel and operating costs and the market
price of electricity; (2) maintaining electric rates at 1996 levels;
and (3) PG&E's ability to continue to collect CTC for the duration of
the recovery period.
The proposal to modify the Diablo Settlement would significantly reduce
the level of PG&E's CTC by reducing the common equity returns on the
Diablo Canyon plant investment to 6.77 percent and accelerating the
capital recovery of the plant and other utility generation-related
assets. If the proposal to freeze customer electric rates is adopted,
PG&E will depreciate and recover the Diablo Canyon plant balance
beginning January 1, 1997, over five years rather than the current
recovery period through 2016. In addition, the proposal would also
limit recovery of most utility generation-related CTC to amounts
collected through 2001.
While it would not adversely affect PG&E's cash flow, PG&E's proposal
to modify Diablo Canyon pricing and implement a customer electric rate
freeze and to accelerate recovery of utility generation-related
investments (including Diablo Canyon) and regulatory assets, would
result in a significant reduction in annual earnings beginning in 1997.
If the revised return currently contemplated for Diablo Canyon had been
adopted for 1995 and PG&E recovered no more than its actual variable
costs under the performance-based Incremental Cost Incentive Price
(ICIP), Diablo Canyon's earnings available for common stock would have
been $115 million, as compared to $492 million. In addition, PG&E's
recovery of revenue based on the performance-based ICIP will depend on
the capacity factor and variable cost assumptions adopted by the CPUC
in implementing PG&E's Diablo Canyon pricing proposal. To the extent
that the actual capacity factor or variable expenses are different than
those adopted by the CPUC in setting the ICIP price, the Company's
earnings would be impacted.
The Company currently accounts for the economic effects of regulation
in accordance with the provisions of Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation," which allows the Company to capitalize certain costs,
that would otherwise have been expensed, as regulatory assets. In
addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of," requires that
regulatory assets be written off when they are no longer probable of
recovery and that impairment losses be recorded for portions of long-
lived assets that are no longer probable of recovery.
When electric generation rates are no longer based on cost of service,
as ultimately contemplated under the CPUC's restructuring decision,
PG&E would discontinue application of SFAS No. 71 for the electric
generation portion of its business. As a result, all applicable
electric generation-related regulatory assets and other transition
costs determined to be probable of CTC recovery would be a regulatory
asset collected through cost-of-service based customer rates and
subject to the provisions to SFAS No. 71. In addition, the CTC account
and electric generation assets will be subject to the criteria of SFAS
No. 121. As a result of applying the provisions of SFAS No. 71, PG&E
had accumulated approximately $1.5 billion of regulatory assets
attributable to electric generation at June 30, 1996. The net
investment in Diablo Canyon and the remaining PG&E-owned generation
assets, including an allocation of common plant, was approximately $4.8
billion and $2.8 billion, respectively, at June 30, 1996. (The above
amounts could vary depending on allocation methods used.) PG&E's
transmission and distribution businesses are expected to remain under
the provisions of SFAS No. 71.
Due to the expected transition cost recovery as provided in the CPUC's
restructuring decision and in PG&E's Diablo Canyon pricing/customer
electric rate freeze proposal, PG&E does not anticipate a material loss
from the discontinuance of SFAS No. 71 or an impairment loss on its
investment in generation assets due to electric industry restructuring.
However, the Company cannot predict the ultimate outcome of the ongoing
changes that are taking place in the electric utility industry or
predict whether such outcome will have a material adverse impact on its
financial position or results of operations. Should final implementing
regulations or any legislation that may be adopted differ significantly
from the CPUC's restructuring decision or PG&E's Diablo Canyon
pricing/customer electric rate freeze proposal, or should full recovery
of generation assets and obligations not be achieved due to changing
costs or limitations imposed by the market or should a CPUC ordered
customer electric rate reduction occur, a material loss could occur.
The Company believes electric industry restructuring will involve a
fundamental change in the way it conducts business. These changes will
impact financial operating trends, resulting in greater earnings
volatility.
Gas Industry Restructuring:
- --------------------------
In an effort to promote competition and increase options for all
customers, as well as to position itself for success in the competitive
marketplace, PG&E is actively pursuing changes in the California gas
industry. In October 1995, PG&E presented a proposal, called the "Gas
Accord," to numerous parties active in the California gas marketplace,
including consumer groups, industrial customers, shippers and
marketers. PG&E has invited these parties to join it in a
collaborative effort to develop a restructuring of the California gas
marketplace.
The Gas Accord proposes three broad initiatives:
(1) Separation of Transmission and Distribution Service and Rates -
PG&E proposes to charge separately for, or unbundle, its gas
transmission and distribution services. This would give industrial and
large commercial (noncore) customers and gas suppliers more flexibility
with respect to the purchase of gas transportation services.
(2) Increased Customer Choice - Under the Gas Accord, PG&E proposes to
give all customers greater ability to choose their gas suppliers in the
future. PG&E has formed an advisory group to help it design a program
that will facilitate opening of the residential and smaller commercial
(core) market to full competition.
(3) Resolution of Existing Regulatory Issues - PG&E also proposes to
settle several outstanding gas regulatory issues that are currently
pending at the CPUC in separate proceedings. These issues include
recovery of costs related to PG&E's capacity commitments with
Transwestern Pipeline Company (Transwestern), PG&E's capacity
commitments with El Paso Natural Gas Company and PGT related to its
noncore customers and the PG&E portion of the PGT/PG&E Pipeline
Expansion Project. (See Note 3 of Notes to Consolidated Financial
Statements.)
Negotiations on the Gas Accord began in October 1995. The Gas Accord,
if adopted, will result in a change in the way PG&E charges for its
transportation services. Any agreement reached by PG&E and other
parties must be approved by the CPUC before it may be implemented.
PG&E has also proposed a significant change to the current gas
ratemaking mechanisms. In December 1994, PG&E filed an application for
approval of a core procurement incentive mechanism (CPIM). If approved
by the CPUC, the CPIM would replace traditional reasonableness reviews
of PG&E's core gas costs with a market benchmark against which PG&E's
actual gas costs would be compared. PG&E would be able to recover its
gas costs under a mechanism through which PG&E would receive benefits
or be penalized depending on whether its actual core procurement costs
were within, below or above a "tolerance band" constructed around the
benchmark. The CPIM proposal requests authorization to use derivative
financial instruments to reduce the risk of gas price and foreign
currency fluctuations. Gains, losses and transaction costs associated
with the use of derivative financial instruments would be included in
the purchased gas account and the measurement against the benchmark.
In April 1996, PG&E filed revised CPIM testimony. In the revised CPIM,
PG&E has agreed to forgo its right to seek recovery of the core
reservation Transwestern costs for the period from 1992 through the end
of 1997, provided the revised CPIM is approved by the CPUC in a manner
satisfactory to PG&E. Hearings on the revised CPIM were held in June
and July 1996. A decision is expected in 1996.
Based on the current status of the Gas Accord and CPIM negotiations,
the Company believes the ultimate outcome of such negotiations,
including resolution of gas regulatory issues, will not have a material
adverse impact on its financial position or results of operations.
Holding Company Structure:
- -------------------------
The PG&E Board of Directors (Board) has authorized, and shareholders
and the FERC have approved, a plan to restructure the corporate
organization of PG&E and its subsidiaries. The result of the change in
corporate structure will be to have PG&E become a separate subsidiary
of a parent holding company (ParentCo) with the present holders of PG&E
common stock becoming holders of ParentCo common stock. As part of the
change in structure, it is contemplated that PG&E will transfer its
ownership interests in its two principal subsidiaries, PGT and
Enterprises, to ParentCo, so that PGT and Enterprises will become
subsidiaries of ParentCo. The debt and preferred stock of PG&E would
remain outstanding at the PG&E level and would not become obligations
or securities of ParentCo.
It is contemplated that these structural changes will be effected as
soon as practicable following receipt of all required regulatory
approvals, including approval by the CPUC and the NRC. An application
for approval by the CPUC was filed by PG&E in October 1995 and PG&E
subsequently filed for approval from the NRC.
Utility Revenue Matters:
- -----------------------
In addition to the CPUC's decision on electric industry restructuring
(discussed above and in Note 2 of Notes to Consolidated Financial
Statements) and various gas proceedings (see Note 3 of Notes to
Consolidated Financial Statements), there are other regulatory matters
with respect to revenues and costs which will affect PG&E's rates in
1996 and beyond. In December 1995, the CPUC issued its decision in
PG&E's 1996 GRC. Based on the GRC decision and the consolidation of the
electric rate cases that became effective January 1, 1996, including
the energy cost, cost of capital and various other proceedings, PG&E's
electric revenue decreased by $443 million from rates in effect in
1995. The GRC decision and various gas proceedings also resulted in an
overall gas revenue decrease of $211 million.
The 1996 GRC proceeding was held open to consider, among other things,
a study to determine the cost effectiveness of the Helms Pumped Storage
Facility (Helms). In July 1996, PG&E submitted its study, which
concluded that the continued operation of Helms is cost effective.
PG&E recommended that the CPUC take no action as a result of the study,
but address Helms along with other generating plants in the context of
electric industry restructuring. PG&E is currently unable to predict
whether there will be a change in rate recovery resulting from the
study. As with its other hydroelectric generating plants, the Company
expects to seek recovery of its net investment in Helms through the
hydroelectric/geothermal PBR and CTC mechanisms. The net investment at
June 30, 1996, was $713 million comprised of the pumped storage
facility (including regulatory assets of $50 million), common plant and
dedicated transmission plant.
Hearings on PG&E's compliance with call center improvements ordered by
the CPUC following severe storms in January and March 1995 have been
completed. A proposed decision was issued by a CPUC administrative law
judge in July 1996. The proposed decision finds that PG&E complied
with all but one of the CPUC performance requirements and recommends a
$1.1 million penalty. The proposed decision suspends the penalty since
performance targets have been met in 1996.
PG&E's service territory experienced additional severe storms and winds
in December 1995, which caused approximately 1.7 million electric
service interruptions. The assigned commissioner in the 1996 GRC
subsequently issued a ruling which ordered hearings on various issues
arising from PG&E's response to the December 1995 wind storms. The
hearings were also called to address potential remedies, including
reparations to customers for reduced reliability, penalties,
disallowances and damages to customers for property loss. Hearings
were held in June 1996, with a CPUC decision expected in the third
quarter of 1996.
During March 1996, PG&E filed an application with the CPUC seeking
approval to modify Diablo Canyon pricing and adopt a customer electric
rate freeze, effective January 1, 1997, which would result in customer
electric rates in the years 1997 through 2001 being the same as those
in effect on January 1, 1996 (see Note 2 of Notes to Consolidated
Financial Statements). The filing seeks to accelerate PG&E's recovery
of utility generation-related transition costs caused by electric
industry restructuring. This accelerated recovery would increase the
1997 Diablo Canyon revenue requirement by $401 million. To achieve the
customer electric rate freeze, PG&E proposes to consolidate the revenue
requirement changes resulting from the proposed modification of Diablo
Canyon pricing and various other applications PG&E has filed, or will
be filing, at the CPUC in 1996. The more significant of these pending
applications are discussed below.
In July 1996, the CPUC released a draft decision dismissing PG&E's
application to increase 1997 base revenues by approximately $156
million. The application requests recovery of expenses for electric
distribution operations and maintenance and call center operations and
provides for an inflation adjustment. At current levels, these
expenses will exceed the amounts authorized in the 1996 GRC. The draft
decision concludes that PG&E failed to demonstrate that extraordinary
circumstances exist to support an exception to the normal rate case
plan, under which base revenues are set only once every three years.
The draft decision has been held by the CPUC for future consideration.
A final decision has not been issued. If PG&E's application to
increase 1997 base revenue is dismissed, PG&E would not receive
explicit recovery in rates for expenses, in excess of those authorized
in the 1996 GRC, it continues to incur.
During April 1996, PG&E filed its 1997 Electric Cost Adjustment Clause
(ECAC) application with the CPUC. The filing was corrected by an
errata filed in May 1996 and updated in June 1996. The updated filing
requests a revenue requirement decrease of approximately $572 million,
composed of an ECAC decrease of approximately $533 million, an Annual
Energy Rate decrease of approximately $10 million, an Energy Revenue
Adjustment Mechanism decrease of approximately $27 million and a
California Alternative Rates for Energy decrease of approximately $2
million.
In July 1996, the Division of Ratepayer Advocates (DRA) filed its
report in PG&E's ECAC proceedings. The DRA recommends a revenue
requirement decrease of $684 million which is $112 million greater than
the revenue requirement decrease proposed by PG&E. However, in light
of PG&E's Diablo Canyon/rate freeze proposal, the DRA recommends that
the CPUC suspend implementation of ECAC rate reductions related to 1997
operations until March 31, 1997, on the assumption that this will allow
the CPUC to complete its analysis of PG&E's Diablo Canyon/Rate Freeze
Proposal. The DRA also recommends that all ECAC revenues accrued from
January 1, 1997, until the CPUC issues a decision on the Diablo
Canyon/rate freeze proposal be refunded to ratepayers at that time.
The DRA recommends that any ECAC overcollection on December 31, 1996,
which the DRA estimates will be $88 million, be returned to ratepayers
as a one-time refund. The DRA's refund recommendations are
inconsistent with PG&E's Diablo Canyon/rate freeze proposal.
In August 1996, PG&E filed a motion requesting that the CPUC adopt an
interim customer electric rate freeze beginning January 1, 1997, and
continuing until the CPUC issues a decision on the Diablo Canyon/rate
freeze proposal. This interim customer electric rate freeze will hold
PG&E's electric revenue requirement at current authorized levels. PG&E
proposes to refund with interest any difference between the interim
customer electric rate freeze and rates authorized by the CPUC in its
final decision on the Diablo Canyon/rate freeze proposal.
In August 1996, the CPUC conditionally approved a joint application by
PG&E, SDG&E and SCE which establishes two tax-exempt trusts for the
purpose of overseeing the costs associated with the development of the
ISO and Exchange. Such costs are estimated to range between $200 and
$300 million and would be financed through bank loans to the trust
supported by guarantees by PG&E and the other utilities. PG&E's
maximum share of the guarantees is $112.5 million. In July 1996, the
CPUC approved, with modifications related to labor and development
costs, PG&E's request to establish a separate memorandum account to
record ISO and Exchange costs incurred by PG&E prior to the
establishment of the funding mechanism described above. CPUC approval
of the memorandum account does not authorize recovery of the related
costs, but instead allows PG&E to seek such recovery at a later date.
In July 1996, PG&E submitted an application proposing to establish a
PBR mechanism for a portion of its electric generation services and a
preliminary unbundling proposal relating to the separation of its
electric rates into various components. See Note 2 of Notes to
Consolidated Financial Statements for further discussion of these
filings.
Results of Operations
- ---------------------
The Company's revenues are derived from three types of operations:
utility (excluding Diablo Canyon and including PGT), Diablo Canyon and
diversified operations (principally Enterprises). The results of
operations for these areas for the three- and six-month periods ended
June 30, 1996, and 1995, are reflected in the following table and
discussed below.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
June 30 Diablo Diversified
(in millions, except per share amounts) Utility Canyon Operations Total
<S> <C> <C> <C> <C>
1996
Operating revenues $ 1,741 $ 372 $ 26 $ 2,139
Operating expenses 1,579 236 36 1,851
------- ------ ------ -------
Operating income (loss) before income taxes $ 162 $ 136 $ (10) $ 288
======= ====== ====== =======
Net income $ 53 $ 58 $ 1 $ 112
======= ====== ====== =======
Earnings per common share $ .12 $ .13 $ .00 $ .25
======= ====== ====== =======
1995
Operating revenues $ 1,857 $ 545 $ 47 $ 2,449
Operating expenses 1,378 190 61 1,629
------- ------ ------ -------
Operating income (loss) before income taxes $ 479 $ 355 $ (14) $ 820
======= ====== ====== =======
Net income $ 212 $ 183 $ 11 $ 406
======= ====== ====== =======
Earnings per common share $ .48 $ .42 $ .02 $ .92
======= ====== ====== =======
SIX MONTHS ENDED
June 30 Diablo Diversified
(in millions, except per share amounts) Utility Canyon Operations Total
1996
Operating revenues $ 3,517 $ 812 $ 58 $ 4,387
Operating expenses 3,040 416 69 3,525
------- ------ ------ -------
Operating income (loss) before income taxes $ 477 $ 396 $ (11) $ 862
======= ====== ====== =======
Net income $ 179 $ 187 $ 6 $ 372
======= ====== ====== =======
Earnings per common share $ .41 $ .44 $ .01 $ .86
======= ====== ====== =======
Total assets at June 30 $19,173 $5,580 $1,005 $25,758
======= ====== ====== =======
1995
Operating revenues $ 3,633 $1,009 $ 115 $ 4,757
Operating expenses 2,712 374 142 3,228
------- ------ ------ -------
Operating income (loss) before income taxes $ 921 $ 635 $ (27) $ 1,529
======= ====== ====== =======
Net income $ 404 $ 322 $ 8 $ 734
======= ====== ====== =======
Earnings per common share $ .89 $ .74 $ .02 $ 1.65
======= ====== ====== =======
Total assets at June 30 $20,012 $5,854 $ 938 $26,804
======= ====== ====== =======
</TABLE>
Earnings Per Common Share:
- -------------------------
Utility earnings per common share for the three- and six-month periods
ended June 30, 1996, were lower than for the comparable periods in
1995, reflecting revenue reductions authorized in the 1996 GRC and
other related rate proceedings. These reductions resulted from lower
cost of capital, declining capital expenditures and reductions in
authorized expense levels. Actual maintenance and other operating
expenses for distribution and customer-related services increased in
1996 and exceeded levels authorized in the 1996 GRC. Also, in July
1996, PG&E settled litigation regarding groundwater contamination near
PG&E's Hinkley Compressor Station, resulting in a charge of $.19 per
common share.
Diablo Canyon earnings per common share for the three- and six-month
periods ended June 30, 1996, were lower than for the comparable periods
in 1995, due to a greater number of scheduled refueling days and
unscheduled outages in 1996. In addition, Diablo Canyon earnings per
common share for the current periods were reduced by a decline in the
price per kWh as provided in the pricing provisions of the Diablo
Settlement.
In June 1995, Enterprises completed the sale of DALEN Corporation
resulting in a gain of $.03 per common share in the three- and six-
month periods ended June 30, 1995.
Common Stock Dividend:
- ---------------------
In July 1996, the Board declared a quarterly dividend of $.49 per
common share which corresponds to an annualized dividend of $1.96 per
common share. PG&E's common stock dividend is based on a number of
financial considerations, including sustainability, financial
flexibility and competitiveness with investment opportunities of
similar risk. PG&E plans to evaluate the level of its common stock
dividend as key issues related to electric industry restructuring are
more clearly resolved.
Operating Revenues:
- ------------------
Operating revenues for the three- and six-month periods ended June 30,
1996, decreased $289 million and $313 million, respectively, compared
to the same periods in 1995. The decrease in both electric and gas
revenues was due to a decrease in authorized revenues as discussed
above. Additionally, Diablo Canyon operating revenues decreased as a
result of a decline in the price per kWh generated and a greater number
of scheduled refueling days and unscheduled outages in 1996 compared to
1995.
Revenues from diversified operations decreased $21 million and $57
million for the three- and six-month periods ended June 30, 1996,
respectively, compared to the same periods in 1995, primarily due to
Enterprises' sale of DALEN Corporation in June 1995.
Operating Expenses:
- ------------------
Operating expenses for the three- and six-month periods ended June 30,
1996, increased $222 million and $298 million, respectively, compared
to the same periods in 1995, primarily due to increases in maintenance
and other operating expenses for distribution and customer-related
services and a charge of $133 million for the settlement of a
litigation claim regarding groundwater contamination near the Hinkley
Compressor Station.
Liquidity and Capital Resources
- -------------------------------
Sources of Capital:
- ------------------
The Company's capital requirements are funded from cash provided by
operations and, to the extent necessary, external financing. The
Company's policy is to finance its assets with a capital structure that
minimizes financing costs, maintains financial flexibility and complies
with regulatory guidelines. This policy ensures that the Company can
raise capital to meet its utility obligation to serve and its other
investment objectives.
During the six-month period ended June 30, 1996, PG&E issued $113
million of common stock, primarily through its Dividend Reinvestment
Program and Savings Fund Plan. PG&E purchased $135 million of its
common stock on the open market during the six-month period ended June
30, 1996.
In May 1996, PG&E refinanced $988 million of variable and fixed
interest rate pollution control revenue bonds with variable interest
rate pollution control revenue bonds. In addition, the Company's
short-term borrowings decreased $774 million during the six-month
period ended June 30, 1996, as the Company used its cash balances to
pay down debt.
Acquisition:
- -----------
In July 1996, the Company completed its acquisition of State Gas
Pipeline, a 376-mile natural gas transportation system in the
Australian state of Queensland. The final purchase price was
approximately $133 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. The Company
had accrued a liability at June 30, 1996, of $152 million for hazardous
waste remediation costs at those sites where such costs are probable
and quantifiable. The costs may be as much as $364 million if, among
other things, 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. This
upper limit of the range of costs was estimated using assumptions less
favorable to the Company, among a range of reasonably possible
outcomes. Costs may be higher if the Company is found to be
responsible for cleanup costs at additional sites or identifiable
possible outcomes change. The Company had recorded a regulatory asset
at June 30, 1996, of $132 million for recovery of these costs in future
rates. (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 material impact on either the Company's
results of operations or financial position.
Significant litigation cases are discussed in Note 5 of Notes to
Consolidated Financial Statements. These cases involve a claim, which
was recently settled, relating to groundwater contamination near
PG&E's Hinkley Compressor Station and a claim that PG&E underpaid
franchise fees.
Accounting for Decommissioning Expense:
- --------------------------------------
The staff of the Securities and Exchange Commission has questioned
certain current accounting practices of the electric utility industry
regarding the recognition, measurement and classification of
decommissioning costs for nuclear generating stations in the financial
statements of electric utilities. In response to these questions, the
Financial Accounting Standards Board (FASB) has issued an Exposure
Draft of a proposed new accounting standard, "Accounting for Certain
Liabilities Related to Closure or Removal of Long-Lived Assets." The
Company would be required to adopt the new standard beginning, at the
earliest, January 1, 1998, but may elect to adopt it earlier.
If issued by the FASB as proposed, the new standard would require,
among other things, that a liability be recognized for decommissioning
costs rather than accruing these costs over time as accumulated
depreciation, with recognition of an increase in the cost of the
related power plant. It would also require, upon initial application,
a cumulative-effect adjustment for the effect on retained earnings had
the provisions of this proposed Statement been applied when those
obligations were incurred. The Company does not believe that such
changes, if required, would have an adverse effect on its results of
operations due to its current and future ability to recover
decommissioning costs through rates.
PART II. OTHER INFORMATION
---------------------------
Item 1. Legal Proceedings
-----------------
Time-of-Use Meter/Customer Notification Litigation
As previously reported in PG&E's Form 10-K for the fiscal year
ended December 31, 1995, in July 1994, Milton L. Grinstead,
Michael Davis, Joan A. Williamson, Frank H. Lacy and Matthew
Doerksen filed a complaint in the Stanislaus County Superior
Court against PG&E on behalf of themselves and purportedly as a
class action on behalf of all of PG&E's customers, for "refund of
unlawfully charged fees." The claims of two of the individual
plaintiffs were dismissed by the Court in April 1995. The
remaining plaintiffs filed an amended complaint in June 1995
which alleged that (a) under certain circumstances, PG&E has a
duty to notify a particular customer of the most favorable rate
for that customer, and (b) PG&E 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 sought classwide damages in excess
of $26 billion and exemplary damages of $100 billion.
In October 1995, the Court granted PG&E's motion to strike the
class and granted summary judgment against one of the remaining
plaintiffs. The Court also held that PG&E does not have an
obligation to advise customers of their best available rates and
is only obligated to give customers notice of rate options.
Although the Court's order gave the remaining plaintiffs an
opportunity to amend their complaint to state a claim based upon
an alleged failure to give them notice of available rate options,
an amended complaint was not filed. On March 5, 1996, the Court
entered judgment in favor of PG&E. Plaintiffs have not appealed
that judgment within the time allowed, and as a result the case
has terminated.
Item 5. Other Information
-----------------
Ratios of Earnings to Fixed Charges and Ratios of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
PG&E's earnings to fixed charges ratio for the six months ended
June 30, 1996 was 2.68. PG&E's earnings to combined fixed
charges and preferred stock dividends ratio for the six months
ended June 30, 1996 was 2.50. Statements setting forth the
computation of the foregoing ratios are filed herewith as
Exhibits 12.1 and 12.2 to Registration Statement Nos. 33-62488,
33-64136 and 33-50707.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 3.1 Bylaws effective as of May 15, 1996
Exhibit 3.2 Bylaws effective as of June 19, 1996
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends
Exhibit 27 Financial Data Schedule
(b) Reports on Form 8-K during the second quarter of 1996 and
through the date hereof:
1. April 18, 1996
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. Interim CTC
2. July 19, 1996
Item 5. Other Events
A. Performance Incentive Plan - Year-to-Date Financial
Results
B. Electric Industry Restructuring
1) Performance Based Ratemaking Proposal
2) Unbundling Proposal
3) Market Power Filing
C. Hinkley Compressor Station Litigation
3. August 2, 1996
Item 5. Other Events
A. Electric Industry Restructuring - Sunk Cost Filing
B. California Legislative Conference Committee on
Electric Industry Restructuring - Response to Data
Request Regarding Stranded Costs
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized.
PACIFIC GAS AND ELECTRIC COMPANY
August 13, 1996 GORDON R. SMITH
By______________________________
GORDON R. SMITH
Senior Vice President and
Chief Financial Officer
EXHIBIT INDEX
Exhibit
Number Exhibit
- ------- ---------------------------------------
3.1 Bylaws effective as of May 15, 1996
3.2 Bylaws effective as of June 19, 1996
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
Exhibit 3.1
Bylaws
of
Pacific Gas and Electric Company
as amended as of May 15, 1996
--------------------------------
Article I.
SHAREHOLDERS.
1. Place of Meeting. All meetings of the shareholders
shall be held at the office of the Corporation in the City and
County of San Francisco, State of California, or at such other
place within the State of California as may be designated by the
Board of Directors.
2. Annual Meetings. The annual meeting of shareholders
shall be held each year on a date and at a time designated by the
Board of Directors.
Written notice of the annual meeting shall be given not less
than ten (or, if sent by third-class mail, thirty) nor more than
sixty days prior to the date of the meeting to each shareholder
entitled to vote thereat. The notice shall state the place, day,
and hour of such meeting, and those matters which the Board, at
the time of mailing, intends to present for action by the
shareholders.
Notice of any meeting of the shareholders shall be given by
mail or telegraphic or other written communication, postage
prepaid, to each holder of record of the stock entitled to vote
thereat, at his address, as it appears on the books of the
Corporation.
3. Special Meetings. Special meetings of the
shareholders shall be called by the Secretary or an Assistant
Secretary at any time on order of the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, or the President. Special
meetings of the shareholders shall also be called by the
Secretary or an Assistant Secretary upon the written request of
holders of shares entitled to cast not less than ten percent of
the votes at the meeting. Such request shall state the purposes
of the meeting, and shall be delivered to the Chairman of the
Board, the Vice Chairman of the Board, the Chairman of the
Executive Committee, the President or the Secretary.
A special meeting so requested shall be held on the date
requested, but not less than thirty-five nor more than sixty days
after the date of the original request. Written notice of each
special meeting of shareholders, stating the place, day, and hour
of such meeting and the business proposed to be transacted
thereat, shall be given in the manner stipulated in Article I,
Section 2, Paragraph 3 of these Bylaws within twenty days after
receipt of the written request.
4. Attendance at Meetings. At any meeting of the
shareholders, each holder of record of stock entitled to vote
thereat may attend in person or may designate an agent or a
reasonable number of agents, not to exceed three to attend the
meeting and cast votes for his shares. The authority of agents
must be evidenced by a written proxy signed by the shareholder
designating the agents authorized to attend the meeting and be
delivered to the Secretary of the Corporation prior to the
commencement of the meeting.
5. No Cumulative Voting. No shareholder of the
Corporation shall be entitled to cumulate his or her voting
power.
Article II.
DIRECTORS.
1. Number. The Board of Directors shall consist of
sixteen (16) directors.
2. Powers. The Board of Directors shall exercise all the
powers of the Corporation except those which are by law, or by
the Articles of Incorporation of this Corporation, or by the
Bylaws conferred upon or reserved to the shareholders.
3. Executive Committee. There shall be an Executive
Committee of the Board of Directors consisting of the Chairman of
the Committee, the Chairman of the Board, if these offices be
filled, the President, and four Directors who are not officers of
the Corporation. The members of the Committee shall be elected,
and may at any time be removed, by a two-thirds vote of the whole
Board.
The Executive Committee, subject to the provisions of law,
may exercise any of the powers and perform any of the duties of
the Board of Directors; but the Board may by an affirmative vote
of a majority of its members withdraw or limit any of the powers
of the Executive Committee.
The Executive Committee, by a vote of a majority of its
members, shall fix its own time and place of meeting, and shall
prescribe its own rules of procedure. A quorum of the Committee
for the transaction of business shall consist of three members.
4. Time and Place of Directors' Meetings. Regular
meetings of the Board of Directors shall be held on such days and
at such times and at such locations as shall be fixed by
resolution of the Board, or designated by the Chairman of the
Board or, in his absence, the Vice Chairman of the Board, or the
President of the Corporation and contained in the notice of any
such meeting. Notice of meetings shall be delivered personally
or sent by mail or telegram at least seven days in advance.
5. Special Meetings. The Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee,
the President, or any five directors may call a special meeting
of the Board of Directors at any time. Notice of the time and
place of special meetings shall be given to each Director by the
Secretary. Such notice shall be delivered personally or by
telephone to each Director at least four hours in advance of such
meeting, or sent by first-class mail or telegram, postage
prepaid, at least two days in advance of such meeting.
6. Quorum. A quorum for the transaction of business at
any meeting of the Board of Directors shall consist of six
members.
7. Action by Consent. Any action required or permitted to
be taken by the Board of Directors may be taken without a meeting
if all Directors individually or collectively consent in writing
to such action. Such written consent or consents shall be filed
with the minutes of the proceedings of the Board of Directors.
8. Meetings by Conference Telephone. Any meeting,
regular or special, of the Board of Directors or of any committee
of the Board of Directors, may be held by conference telephone or
similar communication equipment, provided that all Directors
participating in the meeting can hear one another.
Article III.
OFFICERS.
1. Officers. The officers of the Corporation shall be a
Chairman of the Board, a Vice Chairman of the Board, a Chairman
of the Executive Committee (whenever the Board of Directors in
its discretion fills these offices), a President, one or more
Vice Presidents, a Secretary and one or more Assistant
Secretaries, a Treasurer and one or more Assistant Treasurers, a
General Counsel, a General Attorney (whenever the Board of
Directors in its discretion fills this office), and a Controller,
all of whom shall be elected by the Board of Directors. The
Chairman of the Board, the Vice Chairman of the Board, the
Chairman of the Executive Committee, and the President shall be
members of the Board of Directors.
2. Chairman of the Board. The Chairman of the Board, if
that office be filled, shall preside at all meetings of the
shareholders, of the Directors, and of the Executive Committee in
the absence of the Chairman of that Committee. He shall be the
chief executive officer of the Corporation if so designated by
the Board of Directors. He shall have such duties and
responsibilities as may be prescribed by the Board of Directors
or the Bylaws. The Chairman of the Board shall have authority to
sign on behalf of the Corporation agreements and instruments of
every character, and in the absence or disability of the
President, shall exercise his duties and responsibilities.
3. Vice Chairman of the Board. The Vice Chairman of the
Board, if that office be filled, shall have such duties and
responsibilities as may be prescribed by the Board of Directors,
the Chairman of the Board, or the Bylaws. He shall be the chief
executive officer of the Corporation if so designated by the
Board of Directors. In the absence of the Chairman of the Board,
he shall preside at all meetings of the Board of Directors and of
the shareholders; and, in the absence of the Chairman of the
Executive Committee and the Chairman of the Board, he shall
preside at all meetings of the Executive Committee. The Vice
Chairman of the Board shall have authority to sign on behalf of
the Corporation agreements and instruments of every character.
4. Chairman of the Executive Committee. The Chairman of
the Executive Committee, if that office be filled, shall preside
at all meetings of the Executive Committee. He shall aid and
assist the other officers in the performance of their duties and
shall have such other duties as may be prescribed by the Board of
Directors or the Bylaws.
5. President. The President shall have such duties and
responsibilities as may be prescribed by the Board of Directors,
the Chairman of the Board, or the Bylaws. He shall be the chief
executive officer of the Corporation if so designated by the
Board of Directors. If there be no Chairman of the Board, the
President shall also exercise the duties and responsibilities of
that office. The President shall have authority to sign on
behalf of the Corporation agreements and instruments of every
character.
6. Vice Presidents. Each Vice President shall have such
duties and responsibilities as may be prescribed by the Board of
Directors, the Chairman of the Board, the Vice Chairman of the
Board, the President, or the Bylaws. Each Vice President's
authority to sign agreements and instruments on behalf of the
Corporation shall be as prescribed by the Board of Directors.
The Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, or the President may confer a special
title upon any Vice President.
7. Secretary. The Secretary shall attend all meetings of
the Board of Directors and the Executive Committee, and all
meetings of the shareholders, and he shall record the minutes of
all proceedings in books to be kept for that purpose. He shall
be responsible for maintaining a proper share register and stock
transfer books for all classes of shares issued by the
Corporation. He shall give, or cause to be given, all notices
required either by law or the Bylaws. He shall keep the seal of
the Corporation in safe custody, and shall affix the seal of the
Corporation to any instrument requiring it and shall attest the
same by his signature.
The Secretary shall have such other duties as may be
prescribed by the Board of Directors, the Chairman of the Board,
the Vice Chairman of the Board, the President, or the Bylaws.
The Assistant Secretaries shall perform such duties as may
be assigned from time to time by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the
President, or the Secretary. In the absence or disability of the
Secretary, his duties shall be performed by an Assistant
Secretary.
8. Treasurer. The Treasurer shall have custody of all
moneys and funds of the Corporation, and shall cause to be kept
full and accurate records of receipts and disbursements of the
Corporation. He shall deposit all moneys and other valuables of
the Corporation in the name and to the credit of the Corporation
in such depositaries as may be designated by the Board of
Directors or any employee of the Corporation designated by the
Board of Directors. He shall disburse such funds of the
Corporation as have been duly approved for disbursement.
The Treasurer shall perform such other duties as may from
time to time be prescribed by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws.
The Assistant Treasurer shall perform such duties as may be
assigned from time to time by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the
President, or the Treasurer. In the absence or disability of the
Treasurer, his duties shall be performed by an Assistant
Treasurer.
9. General Counsel. The General Counsel shall be
responsible for handling on behalf of the Corporation all
proceedings and matters of a legal nature. He shall render
advice and legal counsel to the Board of Directors, officers, and
employees of the Corporation, as necessary to the proper conduct
of the business. He shall keep the management of the Corporation
informed of all significant developments of a legal nature
affecting the interests of the Corporation.
The General Counsel shall have such other duties as may from
time to time be prescribed by the Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws.
10. Controller. The Controller shall be responsible for
maintaining the accounting records of the Corporation and for
preparing necessary financial reports and statements, and he
shall properly account for all moneys and obligations due the
Corporation and all properties, assets, and liabilities of the
Corporation. He shall render to the officers such periodic
reports covering the result of operations of the Corporation as
may be required by them or any one of them.
The Controller shall have such other duties as may from time
to time be prescribed by the Board of Directors, the Chairman of
the Board, the Vice Chairman of the Board, the President, or the
Bylaws.
Article IV.
MISCELLANEOUS.
1. Record Date. The Board of Directors may fix a time in
the future as a record date for the determination of the
shareholders entitled to notice of and to vote at any meeting of
shareholders, or entitled to receive any dividend or
distribution, or allotment of rights, or to exercise rights in
respect to any change, conversion, or exchange of shares. The
record date so fixed shall be not more than sixty nor less than
ten days prior to the date of such meeting nor more than sixty
days prior to any other action for the purposes for which it is
so fixed. When a record date is so fixed, only shareholders of
record on that date are entitled to notice of and to vote at the
meeting, or entitled to receive any dividend or distribution, or
allotment of rights, or to exercise the rights, as the case may
be.
2. Transfers of Stock. Upon surrender to the Secretary or
Transfer Agent of the Corporation of a certificate for shares
duly endorsed or accompanied by proper evidence of succession,
assignment, or authority to transfer, and payment of transfer
taxes, the Corporation shall issue a new certificate to the
person entitled thereto, cancel the old certificate, and record
the transaction upon its books. Subject to the foregoing, the
Board of Directors shall have power and authority to make such
rules and regulations as it shall deem necessary or appropriate
concerning the issue, transfer, and registration of certificates
for shares of stock of the Corporation, and to appoint and remove
Transfer Agents and Registrars of transfers.
3. Lost Certificates. Any person claiming a certificate
of stock to be lost, stolen, mislaid, or destroyed shall make an
affidavit or affirmation of that fact and verify the same in such
manner as the Board of Directors may require, and shall, if the
Board of Directors so requires, give the Corporation, its
Transfer Agents, Registrars, and/or other agents a bond of
indemnity in form approved by counsel, and in amount and with
such sureties as may be satisfactory to the Secretary of the
Corporation, before a new certificate may be issued of the same
tenor and for the same number of shares as the one alleged to
have been lost, stolen, mislaid, or destroyed.
4. Employee's Stock Purchase Plan. Subject to any
limitation contained in the Articles of Incorporation, the Board
of Directors may in it discretion, from time to time, authorize
the issue and sale of shares of capital stock of this Corporation
to employees, pursuant to an employee's stock purchase plan, for
such consideration as the Board shall determine to be reasonable.
Such plan may provide for payment for such shares by installments
over a period of time fixed by the Board. In any
such plan, the Board may provide for interest on any installment
payments, and that an employee may cancel his agreement to
purchase all or part of the shares thereunder. The Board may fix
such other terms and conditions for any such plan as it shall
deem, in its discretion, to be in the best interests of this
Corporation. Any such plan may include employees of:
This Corporation's subsidiaries and affiliates; Pacific Service
Employees Association; Pacific Service Federal Credit Union; and
such other associated organizations as may be approved by the
Board.
Article V.
AMENDMENTS.
1. Amendment by Shareholders. Except as otherwise
provided by law, these Bylaws, or any of them, may be amended or
repealed or new Bylaws adopted by the affirmative vote of a
majority of the outstanding shares entitled to vote at any
regular or special meeting of the shareholders.
2. Amendment by Directors. To the extent provided by
law, these Bylaws, or any of them, may be amended or repealed or
new Bylaws adopted by resolution adopted by a majority of the
members of the Board of Directors.
Exhibit 3.2
Bylaws
of
Pacific Gas and Electric Company
as amended as of June 19, 1996
Article I.
SHAREHOLDERS.
1. Place of Meeting. All meetings of the shareholders shall be
held at the office of the Corporation in the City and County of San
Francisco, State of California, or at such other place within the
State of California as may be designated by the Board of Directors.
2. Annual Meetings. The annual meeting of shareholders shall be
held each year on a date and at a time designated by the Board of
Directors.
Written notice of the annual meeting shall be given not less than
ten (or, if sent by third-class mail, thirty) nor more than sixty days
prior to the date of the meeting to each shareholder entitled to vote
thereat. The notice shall state the place, day, and hour of such
meeting, and those matters which the Board, at the time of mailing,
intends to present for action by the shareholders.
Notice of any meeting of the shareholders shall be given by mail
or telegraphic or other written communication, postage prepaid, to
each holder of record of the stock entitled to vote thereat, at his
address, as it appears on the books of the Corporation.
3. Special Meetings. Special meetings of the shareholders shall
be called by the Secretary or an Assistant Secretary at any time on
order of the Board of Directors, the Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee, or the
President. Special meetings of the shareholders shall also be called
by the Secretary or an Assistant Secretary upon the written request of
holders of shares entitled to cast not less than ten percent of the
votes at the meeting. Such request shall state the purposes of the
meeting, and shall be delivered to the Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee, the
President or the Secretary.
A special meeting so requested shall be held on the date
requested, but not less than thirty-five nor more than sixty days
after the date of the original request. Written notice of each
special meeting of shareholders, stating the place, day, and hour of
such meeting and the business proposed to be transacted thereat, shall
be given in the manner stipulated in Article I, Section 2, Paragraph 3
of these Bylaws within twenty days after receipt of the written
request.
4. Attendance at Meetings. At any meeting of the shareholders,
each holder of record of stock entitled to vote thereat may attend in
person or may designate an agent or a reasonable number of agents, not
to exceed three to attend the meeting and cast votes for his shares.
The authority of agents must be evidenced by a written proxy signed by
the shareholder designating the agents authorized to attend the
meeting and be delivered to the Secretary of the Corporation prior to
the commencement of the meeting.
5. No Cumulative Voting. No shareholder of the Corporation
shall be entitled to cumulate his or her voting power.
Article II.
DIRECTORS.
1. Number. The Board of Directors shall consist of sixteen (16)
directors.
2. Powers. The Board of Directors shall exercise all the powers
of the Corporation except those which are by law, or by the Articles
of Incorporation of this Corporation, or by the Bylaws conferred upon
or reserved to the shareholders.
3. Executive Committee. There shall be an Executive Committee
of the Board of Directors consisting of the Chairman of the Committee,
the Chairman of the Board, if these offices be filled, the President,
and four Directors who are not officers of the Corporation. The
members of the Committee shall be elected, and may at any time be
removed, by a two-thirds vote of the whole Board.
The Executive Committee, subject to the provisions of law, may
exercise any of the powers and perform any of the duties of the Board
of Directors; but the Board may by an affirmative vote of a majority
of its members withdraw or limit any of the powers of the Executive
Committee.
The Executive Committee, by a vote of a majority of its members,
shall fix its own time and place of meeting, and shall prescribe its
own rules of procedure. A quorum of the Committee for the transaction
of business shall consist of three members.
4. Time and Place of Directors' Meetings. Regular meetings of
the Board of Directors shall be held on such days and at such times
and at such locations as shall be fixed by resolution of the Board, or
designated by the Chairman of the Board or, in his absence, the Vice
Chairman of the Board, or the President of the Corporation and
contained in the notice of any such meeting. Notice of meetings shall
be delivered personally or sent by mail or telegram at least seven
days in advance.
5. Special Meetings. The Chairman of the Board, the Vice
Chairman of the Board, the Chairman of the Executive Committee, the
President, or any five directors may call a special meeting of the
Board of Directors at any time. Notice of the time and place of
special meetings shall be given to each Director by the Secretary.
Such notice shall be delivered personally or by telephone to each
Director at least four hours in advance of such meeting, or sent by
first-class mail or telegram, postage prepaid, at least two days in
advance of such meeting.
6. Quorum. A quorum for the transaction of business at any
meeting of the Board of Directors shall consist of six members.
7. Action by Consent. Any action required or permitted to be
taken by the Board of Directors may be taken without a meeting if all
Directors individually or collectively consent in writing to such
action. Such written consent or consents shall be filed with the
minutes of the proceedings of the Board of Directors.
8. Meetings by Conference Telephone. Any meeting, regular or
special, of the Board of Directors or of any committee of the Board of
Directors, may be held by conference telephone or similar
communication equipment, provided that all Directors participating in
the meeting can hear one another.
Article III.
OFFICERS.
1. Officers. The officers of the Corporation shall be a Chairman
of the Board, a Vice Chairman of the Board, a Chairman of the
Executive Committee (whenever the Board of Directors in its discretion
fills these offices), a President, one or more Vice Presidents, a
Secretary and one or more Assistant Secretaries, a Treasurer and one
or more Assistant Treasurers, a General Counsel, a General Attorney
(whenever the Board of Directors in its discretion fills this office),
and a Controller, all of whom shall be elected by the Board of
Directors. The Chairman of the Board, the Vice Chairman of the Board,
the Chairman of the Executive Committee, and the President shall be
members of the Board of Directors.
2. Chairman of the Board. The Chairman of the Board, if that
office be filled, shall preside at all meetings of the shareholders,
of the Directors, and of the Executive Committee in the absence of the
Chairman of that Committee. He shall be the chief executive officer
of the Corporation if so designated by the Board of Directors. He
shall have such duties and responsibilities as may be prescribed by
the Board of Directors or the Bylaws. The Chairman of the Board shall
have authority to sign on behalf of the Corporation agreements and
instruments of every character, and in the absence or disability of
the President, shall exercise his duties and responsibilities.
3. Vice Chairman of the Board. The Vice Chairman of the Board,
if that office be filled, shall have such duties and responsibilities
as may be prescribed by the Board of Directors, the Chairman of the
Board, or the Bylaws. He shall be the chief executive officer of the
Corporation if so designated by the Board of Directors. In the
absence of the Chairman of the Board, he shall preside at all meetings
of the Board of Directors and of the shareholders; and, in the absence
of the Chairman of the Executive Committee and the Chairman of the
Board, he shall preside at all meetings of the Executive Committee.
The Vice Chairman of the Board shall have authority to sign on behalf
of the Corporation agreements and instruments of every character.
4. Chairman of the Executive Committee. The Chairman of the
Executive Committee, if that office be filled, shall preside at all
meetings of the Executive Committee. He shall aid and assist the
other officers in the performance of their duties and shall have such
other duties as may be prescribed by the Board of Directors or the
Bylaws.
5. President. The President shall have such duties and
responsibilities as may be prescribed by the Board of Directors, the
Chairman of the Board, or the Bylaws. He shall be the chief executive
officer of the Corporation if so designated by the Board of Directors.
If there be no Chairman of the Board, the President shall also
exercise the duties and responsibilities of that office. The
President shall have authority to sign on behalf of the Corporation
agreements and instruments of every character.
6. Vice Presidents. Each Vice President shall have such duties
and responsibilities as may be prescribed by the Board of Directors,
the Chairman of the Board, the Vice Chairman of the Board, the
President, or the Bylaws. Each Vice President's authority to sign
agreements and instruments on behalf of the Corporation shall be as
prescribed by the Board of Directors. The Board of Directors, the
Chairman of the Board, the Vice Chairman of the Board, or the
President may confer a special title upon any Vice President.
7. Secretary. The Secretary shall attend all meetings of the
Board of Directors and the Executive Committee, and all meetings of
the shareholders, and he shall record the minutes of all proceedings
in books to be kept for that purpose. He shall be responsible for
maintaining a proper share register and stock transfer books for all
classes of shares issued by the Corporation. He shall give, or cause
to be given, all notices required either by law or the Bylaws. He
shall keep the seal of the Corporation in safe custody, and shall
affix the seal of the Corporation to any instrument requiring it and
shall attest the same by his signature.
The Secretary shall have such other duties as may be prescribed by
the Board of Directors, the Chairman of the Board, the Vice Chairman
of the Board, the President, or the Bylaws.
The Assistant Secretaries shall perform such duties as may be
assigned from time to time by the Board of Directors, the Chairman of
the Board, the Vice Chairman of the Board, the President, or the
Secretary. In the absence or disability of the Secretary, his duties
shall be performed by an Assistant Secretary.
8. Treasurer. The Treasurer shall have custody of all moneys
and funds of the Corporation, and shall cause to be kept full and
accurate records of receipts and disbursements of the Corporation. He
shall deposit all moneys and other valuables of the Corporation in the
name and to the credit of the Corporation in such depositaries as may
be designated by the Board of Directors or any employee of the
Corporation designated by the Board of Directors. He shall disburse
such funds of the Corporation as have been duly approved for
disbursement.
The Treasurer shall perform such other duties as may from time to
time be prescribed by the Board of Directors, the Chairman of the
Board, the Vice Chairman of the Board, the President, or the Bylaws.
The Assistant Treasurer shall perform such duties as may be
assigned from time to time by the Board of Directors, the Chairman of
the Board, the Vice Chairman of the Board, the President, or the
Treasurer. In the absence or disability of the Treasurer, his duties
shall be performed by an Assistant Treasurer.
9. General Counsel. The General Counsel shall be responsible
for handling on behalf of the Corporation all proceedings and matters
of a legal nature. He shall render advice and legal counsel to the
Board of Directors, officers, and employees of the Corporation, as
necessary to the proper conduct of the business. He shall keep the
management of the Corporation informed of all significant developments
of a legal nature affecting the interests of the Corporation.
The General Counsel shall have such other duties as may from time
to time be prescribed by the Board of Directors, the Chairman of the
Board, the Vice Chairman of the Board, the President, or the Bylaws.
10. Controller. The Controller shall be responsible for
maintaining the accounting records of the Corporation and for
preparing necessary financial reports and statements, and he shall
properly account for all moneys and obligations due the Corporation
and all properties, assets, and liabilities of the Corporation. He
shall render to the officers such periodic reports covering the result
of operations of the Corporation as may be required by them or any one
of them.
The Controller shall have such other duties as may from time to
time be prescribed by the Board of Directors, the Chairman of the
Board, the Vice Chairman of the Board, the President, or the Bylaws.
He shall be the principal accounting officer of the Corporation,
unless another individual shall be so designated by the Board of
Directors.
Article IV.
MISCELLANEOUS.
1. Record Date. The Board of Directors may fix a time in the
future as a record date for the determination of the shareholders
entitled to notice of and to vote at any meeting of shareholders, or
entitled to receive any dividend or distribution, or allotment of
rights, or to exercise rights in respect to any change, conversion, or
exchange of shares. The record date so fixed shall be not more than
sixty nor less than ten days prior to the date of such meeting nor
more than sixty days prior to any other action for the purposes for
which it is so fixed. When a record date is so fixed, only
shareholders of record on that date are entitled to notice of and to
vote at the meeting, or entitled to receive any dividend or
distribution, or allotment of rights, or to exercise the rights, as
the case may be.
2. Transfers of Stock. Upon surrender to the Secretary or
Transfer Agent of the Corporation of a certificate for shares duly
endorsed or accompanied by proper evidence of succession, assignment,
or authority to transfer, and payment of transfer taxes, the
Corporation shall issue a new certificate to the person entitled
thereto, cancel the old certificate, and record the transaction upon
its books. Subject to the foregoing, the Board of Directors shall
have power and authority to make such rules and regulations as it
shall deem necessary or appropriate concerning the issue, transfer,
and registration of certificates for shares of stock of the
Corporation, and to appoint and remove Transfer Agents and Registrars
of transfers.
3. Lost Certificates. Any person claiming a certificate of
stock to be lost, stolen, mislaid, or destroyed shall make an
affidavit or affirmation of that fact and verify the same in such
manner as the Board of Directors may require, and shall, if the Board
of Directors so requires, give the Corporation, its Transfer Agents,
Registrars, and/or other agents a bond of indemnity in form approved
by counsel, and in amount and with such sureties as may be
satisfactory to the Secretary of the Corporation, before a new
certificate may be issued of the same tenor and for the same number of
shares as the one alleged to have been lost, stolen, mislaid, or
destroyed.
4. Employee's Stock Purchase Plan. Subject to any limitation
contained in the Articles of Incorporation, the Board of Directors may
in it discretion, from time to time, authorize the issue and sale of
shares of capital stock of this Corporation to employees, pursuant to
an employee's stock purchase plan, for such consideration as the Board
shall determine to be reasonable. Such plan may provide for payment
for such shares by installments over a period of time fixed by the
Board. In any
such plan, the Board may provide for interest on any installment
payments, and that an employee may cancel his agreement to purchase
all or part of the shares thereunder. The Board may fix such other
terms and conditions for any such plan as it shall deem, in its
discretion, to be in the best interests of this Corporation. Any such
plan may include employees of: This Corporation's subsidiaries and
affiliates; Pacific Service Employees Association; Pacific Service
Federal Credit Union; and such other associated organizations as may
be approved by the Board.
Article V.
AMENDMENTS.
1. Amendment by Shareholders. Except as otherwise provided by
law, these Bylaws, or any of them, may be amended or repealed or new
Bylaws adopted by the affirmative vote of a majority of the
outstanding shares entitled to vote at any regular or special meeting
of the shareholders.
2. Amendment by Directors. To the extent provided by law, these
Bylaws, or any of them, may be amended or repealed or new Bylaws
adopted by resolution adopted by a majority of the members of the
Board of Directors.
<TABLE>
EXHIBIT 11
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF EARNINGS PER COMMON SHARE
(unaudited)
<CAPTION>
- --------------------------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
-------------------- --------------------
(in thousands, except per share amounts) 1996 1995 1996 1995
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Net income $111,780 $405,520 $372,484 $734,207
Less: preferred dividend requirement and
redemption premium 8,278 14,494 16,556 28,988
-------- -------- -------- --------
Net income for calculating EPS for
Statement of Consolidated Income $103,502 $391,026 $355,928 $705,219
======== ======== ======== ========
Average common shares outstanding 415,125 426,621 414,738 428,344
======== ======== ======== ========
EPS as shown in the Statement of
Consolidated Income $ .25 $ .92 $ .86 $ 1.65
======== ======== ======== ========
PRIMARY EPS (1)
Net income $111,780 $405,520 $372,484 $734,207
Less: preferred dividend requirement and
redemption premium 8,278 14,494 16,556 28,988
-------- -------- -------- --------
Net income for calculating primary EPS $103,502 $391,026 $355,928 $705,219
======== ======== ======== ========
Average common shares outstanding 415,125 426,621 414,738 428,344
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) 8 133 20 88
-------- -------- -------- --------
Average common shares outstanding as
adjusted 415,133 426,754 414,758 428,432
======== ======== ======== ========
Primary EPS $ .25 $ .92 $ .86 $ 1.65
======== ======== ======== ========
FULLY DILUTED EPS (1)
Net income $111,780 $405,520 $372,484 $734,207
Less: preferred dividend requirement and
redemption premium 8,278 14,494 16,556 28,988
-------- -------- -------- --------
Net income for calculating fully diluted EPS $103,502 $391,026 $355,928 $705,219
======== ======== ======== ========
Average common shares outstanding 415,125 426,621 414,738 428,344
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) 9 184 20 184
-------- -------- -------- --------
Average common shares outstanding as
adjusted 415,134 426,805 414,758 428,528
======== ======== ======== ========
Fully diluted EPS $ .25 $ .92 $ .86 $ 1.65
======== ======== ======== ========
- --------------------------------------------------------------------------------------------
<FN>
(1) This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K.
This presentation is not required by APB Opinion No. 15, because it results in dilution
of less than 3%.
</TABLE>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Six Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) 6/30/96 1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 372,484 $1,338,885 $1,007,450 $1,065,495 $1,170,581 $1,026,392
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
undistributed losses
(income) of less than
50% owned affiliates (4,430) 3,820 (2,764) 6,895 (3,349) 26,671
Income tax expense 219,297 895,289 836,767 901,890 895,126 851,534
Net fixed charges 349,457 715,975 730,965 821,166 802,198 776,682
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $ 936,808 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 290,641 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185
Interest on short-
term borrowings 44,874 83,024 77,295 87,819 61,182 77,760
Interest on capital
leases 1,781 2,735 1,758 1,737 1,737 1,737
Capitalized interest 192 957 2,660 46,055 6,511 6,107
Earnings required to
cover the preferred
stock dividend and
preferred security
distribution requirements
of majority owned
subsidiaries 12,378 3,306 - - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed
Charges $ 349,866 $ 717,397 $ 733,625 $ 867,221 $ 808,709 $ 782,789
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Fixed Charges 2.68 4.12 3.51 3.22 3.54 3.43
- ---------------------------------------------------------------------------------------------------
<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 and short-term borrowings (including a representative portion
of rental expense); amortization of bond premium, discount and expense; interest on capital
leases; pretax earnings required to cover the preferred stock dividend requirements of
majority owned subsidiaries; and after-tax earnings required to cover the preferred security
distribution requirements of majority owned subsidiaries.
</TABLE>
<TABLE>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Six Months Year ended December 31,
Ended ----------------------------------------------------------
(dollars in thousands) 6/30/96 1995 1994 1993 1992 1991
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 372,484 $1,338,885 $1,007,450 $1,065,495 $1,170,581 $1,026,392
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 (4,430) 3,820 (2,764) 6,895 (3,349) 26,671
Income tax expense 219,297 895,289 836,767 901,890 895,126 851,534
Net fixed charges 349,457 715,975 730,965 821,166 802,198 776,682
---------- ---------- ---------- ---------- ---------- ----------
Total Earnings $ 936,808 $2,953,969 $2,572,418 $2,795,446 $2,864,556 $2,681,279
========== ========== ========== ========== ========== ==========
Fixed Charges:
Interest on long-
term debt $ 290,641 $ 627,375 $ 651,912 $ 731,610 $ 739,279 $ 697,185
Interest on short-
term borrowings 44,874 83,024 77,295 87,819 61,182 77,760
Interest on capital
leases 1,781 2,735 1,758 1,737 1,737 1,737
Capitalized interest 192 957 2,660 46,055 6,511 6,107
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned subsidiaries 12,378 3,306 - - - -
---------- ---------- ---------- ---------- ---------- ----------
Total Fixed Charges 349,866 717,397 733,625 867,221 808,709 782,789
---------- ---------- ---------- ---------- ---------- ----------
Preferred Stock Dividends:
Tax deductible dividends 5,029 11,343 4,672 4,814 5,136 5,136
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 19,552 99,984 96,039 108,937 130,147 154,404
---------- ---------- ---------- ---------- ---------- ----------
Total Preferred
Stock Dividends 24,581 111,327 100,711 113,751 135,283 159,540
---------- ---------- ---------- ---------- ---------- ----------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 374,447 $ 828,724 $ 834,336 $ 980,972 $ 943,992 $ 942,329
========== ========== ========== ========== ========== ==========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.50 3.56 3.08 2.85 3.03 2.85
- ---------------------------------------------------------------------------------------------------
<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; pretax earnings required to cover
the preferred stock dividend requirements of majority owned subsidiaries; and the after-tax
earnings required to cover the preferred security distribution 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 increased to an amount
representing pretax earnings which would be required to cover such dividend requirements.
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> JUN-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 18,795,564
<OTHER-PROPERTY-AND-INVEST> 1,780,165
<TOTAL-CURRENT-ASSETS> 2,572,404
<TOTAL-DEFERRED-CHARGES> 2,609,968
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 25,758,101
<COMMON> 2,064,488
<CAPITAL-SURPLUS-PAID-IN> 3,753,964
<RETAINED-EARNINGS> 2,700,704
<TOTAL-COMMON-STOCKHOLDERS-EQ> 8,519,156
437,500
402,056
<LONG-TERM-DEBT-NET> 7,923,496
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 56,073
<LONG-TERM-DEBT-CURRENT-PORT> 221,133
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 8,198,687
<TOT-CAPITALIZATION-AND-LIAB> 25,758,101
<GROSS-OPERATING-REVENUE> 4,387,434
<INCOME-TAX-EXPENSE> 219,297
<OTHER-OPERATING-EXPENSES> 3,525,665
<TOTAL-OPERATING-EXPENSES> 3,525,665
<OPERATING-INCOME-LOSS> 861,769
<OTHER-INCOME-NET> 65,424
<INCOME-BEFORE-INTEREST-EXPEN> 927,193
<TOTAL-INTEREST-EXPENSE> 335,412
<NET-INCOME> 372,484
16,556
<EARNINGS-AVAILABLE-FOR-COMM> 355,928
<COMMON-STOCK-DIVIDENDS> 404,138
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 1,378,001
<EPS-PRIMARY> 0.86
<EPS-DILUTED> 0.86
</TABLE>
