FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
----------------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
---------- ----------
Exact Name of
Commission Registrant State or other IRS Employer
File as specified Jurisdiction of Identification
Number in its charter Incorporation Number
- ----------- -------------- --------------- --------------
1-12609 PG&E Corporation California 94-3234914
1-2348 Pacific Gas and California 94-0742640
Electric Company
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California 94177 San Francisco, California
94105
- ------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Pacific Gas and Electric Company PG&E Corporation
(415) 973-7000 (415) 267-7000
- -------------------------------------------------------------------
Registrant's telephone number, including area code
Indicate by check mark whether the registrants (1) have 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) have been subject to
such filing requirements for the past 90 days.
Yes X No
---------- -----------
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common Stock Outstanding October 23, 1998:
PG&E Corporation 382,515,765 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
<PAGE>
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBR 30, 1998
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME........................1
CONDENSED BALANCE SHEET.................................2
STATEMENT OF CASH FLOWS ................................3
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME........................4
CONDENSED BALANCE SHEET.................................5
STATEMENT OF CASH FLOWS.................................6
NOTE 1: GENERAL...........................................7
NOTE 2: THE ELECTRIC BUSINESS.............................9
NOTE 3: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED DEBENTURES...........16
NOTE 4: COMMITMENTS AND CONTINGENCIES....................16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED
RESULTS OF OPERATIONS AND FINANCIAL CONDITION.............18
RESULTS OF OPERATIONS.....................................20
Common Stock Dividend..................................20
Earnings Per Common Share..............................21
Utility Results........................................21
Unregulated Business Results...........................22
FINANCIAL CONDITION.......................................22
COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........22
THE UTILITY ELECTRIC GENERATION BUSINESS..................22
Competitive Market Framework...........................22
Electric Transition Plan...............................23
Rate Freeze and Rate Reduction.........................24
Transition Cost Recovery...............................24
Utility Generation Divestiture.........................26
Utility Generation Impairment..........................27
Customer Impacts of Transition Plan....................28
California Voter Initiative............................28
THE UTILITY ELECTRIC TRANSMISSION BUSINESS................29
THE UTILITY ELECTRIC DISTRIBUTION BUSINESS................30
THE UTILITY GAS BUSINESS..................................30
UNREGULATED BUSINESS OPERATIONS...........................31
PG&E CORPORATION..........................................31
ACQUISITIONS AND SALES....................................31
YEAR 2000.................................................32
LIQUIDITY AND CAPITAL RESOURCES
Sources of Capital.....................................35
Utility Cost of Capital................................36
1999 General Rate Case.................................37
Environmental Matters..................................37
Legal Matters..........................................37
Risk Management Activities.............................38
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................38
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.........................................39
ITEM 5. OTHER INFORMATION.........................................40
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................40
SIGNATURE..........................................................42
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME
(in millions, except per share amounts)
<CAPTION>
Three months ended Nine months ended
September 30, September 30,
1998 1997 1998 1997
-------- -------- -------- -------
<S> <C> <C> <C> <C>
Operating Revenues
Utility $ 2,563 $ 2,541 $ 6,706 $ 7,094
Energy commodities and services 2,744 1,522 7,741 3,417
-------- -------- -------- --------
Total operating revenues 5,307 4,063 14,447 10,511
-------- -------- -------- --------
Operating Expenses
Cost of energy for utility 714 779 1,949 2,162
Cost of energy commodities and services 2,557 1,412 7,177 3,165
Operating and maintenance, net 925 771 2,041 2,324
Depreciation and decommissioning 569 473 1,713 1,397
-------- -------- -------- --------
Total operating expenses 4,765 3,435 12,880 9,048
-------- -------- -------- --------
Operating Income 542 628 1,567 1,463
Interest expense, net 199 174 604 497
Other income 8 20 24 114
-------- -------- -------- --------
Income Before Income Taxes 351 474 987 1,080
Income taxes 141 217 464 458
-------- -------- -------- --------
Net Income $ 210 $ 257 $ 523 $ 622
======== ======== ======== ========
Weighted Average Common Shares
Outstanding 382 414 382 407
Earnings Per Common Share, Basic and Diluted $ .55 $ .62 $ 1.37 $ 1.53
Dividends Declared Per Common Share $ .30 $ .30 $ .90 $ .90
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
CONDENSED BALANCE SHEET
(in millions)
<CAPTION>
Balance at September 30, December 31,
1998 1997
------------ -----------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 278 $ 237
Short-term investments 33 1,160
Accounts receivable
Customers, net 1,722 1,514
Regulatory balancing accounts 277 658
Energy marketing 736 830
Inventories and prepayments 792 626
-------- --------
Total current assets 3,838 5,025
Property, Plant, and Equipment
Utility 24,067 24,185
Gas transmission 3,385 3,484
Other 2,548 57
-------- --------
Total property, plant, and equipment (at original cost) 30,000 27,726
Accumulated depreciation and decommissioning (11,794) (11,617)
-------- --------
Net property, plant, and equipment 18,206 16,109
Other Noncurrent Assets
Regulatory assets 6,034 6,700
Nuclear decommissioning funds 1,070 1,024
Other 2,490 1,699
-------- --------
Total noncurrent assets 9,594 9,423
-------- --------
TOTAL ASSETS $ 31,638 $ 30,557
======== ========
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 1,937 $ 103
Current portion of long-term debt 358 734
Current portion of rate reduction bonds 197 125
Accounts payable
Trade creditors 770 754
Other 455 466
Energy marketing 587 758
Accrued taxes 725 226
Other 1,077 893
-------- --------
Total current liabilities 6,106 4,059
Noncurrent Liabilities
Long-term debt 7,060 7,584
Rate reduction bonds 2,511 2,776
Deferred income taxes 3,717 4,029
Deferred tax credits 294 339
Other 3,211 1,978
-------- --------
Total noncurrent liabilities 16,793 16,706
Preferred Stock of Subsidiary With Mandatory Redemption Provisions 137 137
Utility Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures 300 300
Stockholders' Equity
Preferred stock of subsidiary without mandatory redemption provisions
Nonredeemable 145 145
Redeemable 198 313
Common stock 5,848 6,366
Reinvested earnings 2,111 2,531
-------- --------
Total stockholders' equity 8,302 9,355
Commitments and Contingencies (Notes 2 and 4) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 31,638 $ 30,557
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
STATEMENT OF CASH FLOWS
(in millions)
<CAPTION>
For the nine months ended September 30, 1998 1997
---------- ----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 523 $ 622
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning, and amortization 1,792 1,489
Deferred income taxes and tax credits-net (309) (196)
Other deferred charges and noncurrent liabilities (1,071) 136
Gain on sale of assets - (120)
Loss on sale of assets 21 -
Net effect of changes in operating assets
and liabilities:
Accounts receivable 704 (52)
Regulatory balancing accounts receivable 618 2
Inventories (45) (46)
Accounts payable (118) (94)
Accrued taxes 501 321
Other working capital (101) (73)
Other-net - 179
--------- ---------
Net cash provided by operating activities 2,515 2,168
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (1,262) (1,181)
Investments in unregulated projects 17 (165)
Acquisitions (425) (41)
Proceeds from sale of assets 58 -
Other-net 218 153
--------- ---------
Net cash used by investing activities (1,394) (1,234)
--------- ---------
Cash Flows From Financing Activities
Common stock issued 48 40
Common stock repurchased (1,159) (704)
Long-term debt issued 139 363
Long-term debt matured, redeemed, or repurchased-net (1,295) (436)
Short-term debt issued (redeemed)-net 507 643
Preferred stock redeemed or repurchased (105) (7)
Dividends paid (377) (389)
Other-net 35 (20)
--------- ---------
Net cash used by financing activities (2,207) (510)
--------- ---------
Net Change in Cash and Cash Equivalents (1,086) 424
Cash and Cash Equivalents at January 1 1,397 143
--------- ---------
Cash and Cash Equivalents at September 30 $ 311 $ 567
--------- ---------
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 527 $ 372
Income taxes 264 352
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(in millions)
<CAPTION>
Three months ended Nine months ended
September 30, September 30,
1998 1997 1998 1997
-------- -------- -------- ------
<S> <C> <C> <C> <C>
Electric utility $ 2,226 $ 2,161 $ 5,496 $ 5,760
Gas utility 337 380 1,210 1,334
-------- -------- -------- --------
Total operating revenues 2,563 2,541 6,706 7,094
-------- -------- -------- --------
Operating Expenses
Cost of electric energy 663 730 1,616 1,837
Cost of gas 51 49 333 325
Operating and maintenance, net 641 695 2,055 2,159
Depreciation and decommissioning 528 441 1,602 1,332
Provision for regulatory adjustment mechanisms 154 - (349) -
-------- -------- -------- --------
Total operating expenses 2,037 1,915 5,257 5,653
-------- -------- -------- --------
Operating Income 526 626 1,449 1,441
Interest expense, net 160 146 493 437
Other income and (expense) 7 17 78 40
-------- -------- -------- -------
Income Before Income Taxes 373 497 1,034 1,044
Income taxes 168 220 480 465
-------- -------- -------- -------
Net Income 205 277 554 579
Preferred dividend requirement and
redemption premium 6 8 21 25
-------- -------- -------- -------
Income Available for Common Stock $ 199 $ 269 $ 533 $ 554
======== ======== ======== =======
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEET
(in millions)
<CAPTION>
Balance at
September 30, December 31,
1998 1997
----------- -----------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 78 $ 80
Short-term investments 15 1,143
Accounts receivable
Customers, net 1,295 1,204
Regulatory balancing accounts 277 658
Related parties accounts receivable 28 459
Inventories and prepayments 482 523
-------- --------
Total current assets 2,175 4,067
Property, Plant, and Equipment
Electric 17,006 17,246
Gas 7,061 6,939
-------- --------
Total property, plant, and equipment (at original cost) 24,067 24,185
Accumulated depreciation and decommissioning (11,209) (11,134)
-------- --------
Net property, plant, and equipment 12,858 13,051
Other Noncurrent Assets
Regulatory assets 5,991 6,646
Nuclear decommissioning funds 1,070 1,024
Other 374 359
-------- --------
Total noncurrent assets 7,435 8,029
-------- --------
TOTAL ASSETS $ 22,468 $ 25,147
======== ========
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 10 $ -
Current portion of long-term debt 275 655
Current portion of rate reduction bonds 197 125
Accounts payable
Trade creditors 514 441
Related parties 61 134
Other 414 424
Accrued taxes 494 229
Deferred income taxes 52 149
Other 554 527
-------- --------
Total current liabilities 2,571 2,684
Noncurrent Liabilities
Long-term debt 5,569 6,143
Rate reduction bonds 2,511 2,776
Deferred income taxes 3,000 3,304
Deferred tax credits 294 338
Other 1,807 1,810
-------- --------
Total noncurrent liabilities 13,181 14,371
Preferred Stock of Subsidiary With Mandatory Redemption Provisions 137 137
Company Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures 300 300
Stockholders' Equity
Preferred stock without mandatory redemption provisions
Nonredeemable 145 145
Redeemable 142 257
Common stock 3,806 4,582
Reinvested earnings 2,186 2,671
-------- --------
Total stockholders' equity 6,279 7,655
Commitments and Contingencies (Notes 2 and 4) -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 22,468 $ 25,147
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(in millions)
<CAPTION>
For the nine months ended September 30, 1998 1997
-------- --------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 554 $ 579
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning, and amortization 1,697 1,424
Deferred income taxes and tax credits-net (297) (220)
Other deferred charges and noncurrent liabilities (243) 132
Provision for regulatory adjustment mechanisms (349) -
Net effect of changes in operating assets
and liabilities:
Accounts receivable 339 (163)
Regulatory balancing accounts receivable 618 2
Inventories 7 (17)
Accounts payable 116 (116)
Accrued taxes 265 336
Other working capital 24 (60)
Other-net 24 23
--------- ---------
Net cash provided by operating activities 2,755 1,920
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (963) (1,116)
Other-net 297 (90)
--------- ---------
Net cash used by investing activities (666) (1,206)
--------- ---------
Cash Flows From Financing Activities
Common stock repurchased (1,600) -
Long-term debt issued 2 355
Long-term debt matured, redeemed, or repurchased-net (1,175) (334)
Short-term debt issued (redeemed)-net - 132
Preferred stock redeemed or repurchased (107) -
Dividends paid (337) (548)
Other-net (2) (10)
--------- ---------
Net cash used by financing activities (3,219) (405)
Net Change in Cash and Cash Equivalents (1,130) 309
Cash and Cash Equivalents at January 1 1,223 143
--------- ---------
Cash and Cash Equivalents at September 30 $ 93 $ 452
--------- ---------
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 401 $ 329
Income taxes 587 406
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: GENERAL
Basis of Presentation:
- ----------------------
This Quarterly Report Form 10-Q is a combined report of PG&E Corporation and
Pacific Gas and Electric Company (the Utility), a regulated subsidiary of
PG&E Corporation. The Notes to Consolidated Financial Statements apply to
both PG&E Corporation and the Utility. PG&E Corporation's consolidated
financial statements include the accounts of PG&E Corporation and its wholly
owned and controlled subsidiaries, including the Utility (collectively, the
Corporation). The Utility's consolidated financial statements include its
accounts as well as those of its wholly owned and controlled subsidiaries.
The Utility's financial position and results of operations are the
principal factors affecting the Corporation's consolidated financial
position and results of operations. This quarterly report should be read
in conjunction with the Corporation's and the Utility's Consolidated
Financial Statements and Notes to Consolidated Financial Statements
incorporated by reference in their combined 1997 Annual Report Form on 10-K.
PG&E Corporation believes that the accompanying statements reflect all
adjustments necessary to present a fair statement of the consolidated
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. All significant intercompany transactions have
been eliminated from the consolidated financial statements. Certain amounts
in the prior year's consolidated financial statements have been reclassified
to conform to the 1998 presentation. Results of operations for interim
periods are not necessarily indicative of results to be expected for a full
year.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions. These estimates and assumptions affect the reported amounts of
revenues, expenses, assets, and liabilities and the disclosure of
contingencies. Actual results could differ from these estimates.
Acquisitions and Sales:
- -----------------------
In July 1998, the Corporation sold its Australian energy holdings to Duke
Energy International, LLP (DEI), a subsidiary of Duke Energy Corporation.
The assets, located in the southeast corner of the Australian state of
Queensland, include a 627-kilometer gas pipeline, pipeline operations, and
trading and marketing operations.
The sale to DEI represents a premium on the price in local currency of
the Corporation's 1996 investment in the assets. However, the transaction
resulted in a non-recurring charge of $.06 per share in the second quarter,
primarily due to the 22 percent currency devaluation of the Australian
dollar against the U.S. dollar during the past two years.
On September 1, 1998, the Corporation, through its subsidiary U.S.
Generating Company (USGen), completed the acquisition of a portfolio of
electric generating assets and power supply contracts from the New England
Electric System (NEES) for $1.59 billion, plus $85 million for early
retirement and severance costs previously committed to by NEES. The
acquisition has been accounted for using the purchase method of accounting.
Accordingly, the purchase price has been preliminarily allocated to the
<PAGE>
assets purchased and the liabilities assumed based upon the fair values at
the date of acquisition.
Including fuel and other inventories and transaction costs, the
Corporation's financing requirements total approximately $1.8 billion,
funded through $1.3 billion of USGen debt and a $425 million equity
contribution. The net purchase price has been preliminarily allocated as
follows: (1) Property, plant, and equipment of $2.3 billion; (2) Receivable
for support payments of $0.8 billion; and (3) Contractual obligations of
$1.3 billion. The assets include hydroelectric, coal, oil, and natural gas
generation facilities with a combined generating capacity of 4,000 megawatts
(MW). In addition, USGen assumed 25 multi-year power purchase agreements
representing an additional 800 MW of production capacity. USGen entered
into agreements with NEES as part of the acquisition, which: (1) provide
that NEES shall make support payments over the next ten years to USGen for
the purchase power agreements; and (2) require that USGen provide
electricity to NEES under contracts that expire over the next four to twelve
years.
The Corporation acquired NEES's generating facilities and power supply
contracts in anticipation of deregulation of the electric industry in
several New England states. In Massachusetts, electric industry
restructuring legislation opened retail competition in the electric
generation business on March 1, 1998. However, a referendum requesting
voters to approve the continuation of this legislation in Massachusetts is
on the November 1998 ballot. If the voters vote to reject the legislation,
then the restructuring legislation in Massachusetts will be repealed. The
Corporation does not expect that a repeal of the Massachusetts legislation,
which relates primarily to the retail electricity market, would have a
material impact on its results of operations or financial position.
Accounting for Risk Management Activities:
- ------------------------------------------
The Corporation, through its subsidiaries, engages in price risk management
activities for both non-hedging and hedging purposes. The Corporation
conducts non-hedging activities principally through its unregulated
subsidiary, PG&E Energy Trading. Derivative and other financial instruments
associated with the Corporation's electric power, natural gas, and related
non-hedging activities are accounted for using the mark-to-market method of
accounting.
Under mark-to-market accounting, the Corporation's electric power,
natural gas, and related non-hedging contracts, including both physical and
financial instruments, are recorded at market value, net of future servicing
costs and reserves. In the period of contract execution, income or expense
is recognized. The market prices used to value these transactions reflect
management's best estimates considering various factors, including market
quotes, time value, and volatility factors of the underlying commitments.
The values are adjusted to reflect the potential impact of liquidating a
position in an orderly manner over a reasonable period of time under present
market conditions.
Changes in the market value (determined by reference to recent
transactions) of these contract portfolios, resulting primarily from newly
originated transactions and the impact of commodity price and interest rate
movements, are recognized in operating revenue in the period of change.
These unrealized gains and losses and related reserves are recorded as
inventories and prepayments and other liabilities.
In addition to the non-hedging activities discussed above, the
Corporation may engage in hedging activities using futures, options, and
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies. The Corporation accounts for hedge
transactions under the deferral method. Initially, the Corporation defers
gains and losses on these transactions and classifies them as Inventories
and prepayments and Other liabilities in the Consolidated Balance Sheet.
When the hedged transaction occurs, the Corporation recognizes the gain or
loss in Cost of energy commodities and services or interest expense in the
Statement of Consolidated Income.
For regulatory reasons, the Utility manages price risk independently from
the activities in the Corporation's unregulated businesses. In the first
quarter of 1998, the California Public Utility Commission (CPUC) granted
approval for the Utility to use financial instruments to manage price
volatility of gas purchased for the Utility's electric generation portfolio.
The approval limits the Utility's outstanding financial instruments to $200
million, with downward adjustments occurring as the Utility divests its
fossil-fueled generation plants. (See Utility Generation Divestiture,
below.) Authority to use these risk management instruments ceases upon the
full divestiture of fossil-fueled generation plants or at the end of the
current electric rate freeze (see Rate Freeze and Rate Reduction, below),
whichever comes first.
In the second quarter of 1998, the CPUC granted conditional authority to
the Utility to use natural gas-based financial instruments to manage the
impact of natural gas prices on the cost of electricity purchased pursuant
to existing power purchase contracts. Under the authority granted in the
CPUC decision, no natural gas-based financial instruments shall have an
expiration date later than December 31, 2001. Further, if the rate freeze
ends before December 31, 2001, the Utility shall net any outstanding
financial instrument contracts through equal and opposite contracts, within
a reasonable amount of time. Also during the second quarter, the Utility
filed an application with the CPUC to use natural gas-based financial
instruments to manage price and revenue risks associated with its natural
gas transmission and storage assets. The Utility currently does not use
financial instruments to manage price risk.
The Corporation's net gains and losses associated with price risk
management activities for the three- and nine-month periods ended September
30, 1998, were not material.
In June 1998, the Financial Accounting Standards Board issued Statement
No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
which is required to be adopted in years beginning after June 15, 1999. The
Statement permits early adoption as of the beginning of any fiscal quarter.
The Corporation expects to adopt the new Statement no later than January 1,
2000. The Statement will require the Corporation to recognize all
derivatives, as defined in the Statement, on the balance sheet at fair
value. Derivatives, or any portion thereof, that are not effective hedges
must be adjusted to fair value through income. If the derivative is an
effective hedge, depending on the nature of the hedge, changes in the fair
value of derivatives either will be offset against the change in fair value
of the hedged assets, liabilities, or firm commitments through earnings or
will be recognized in other comprehensive income until the hedged item is
recognized in earnings. The Corporation currently is evaluating what the
effect of Statement 133 will be on the earnings and financial position of
the Corporation.
NOTE 2: The Utility Electric Generation Business
On March 31, 1998, California became one of the first states in the country
to allow open competition in the electric generation business. Today, many
Californians may choose an energy service provider, which will provide their
electric power generation. The Utility's customers may choose to purchase
electricity: (1) from the Utility; (2) from retail electricity providers
(for example, marketers including our energy service subsidiary, brokers,
and aggregators); or (3) directly from unregulated power generators. The
<PAGE>
Utility expects to continue to provide distribution services to
substantially all electric consumers within its service territory.
Competitive Market Framework:
- -----------------------------
To create the competitive generation market, California established a Power
Exchange (PX) and an Independent Systems Operator (ISO). The PX sets
electricity prices in an open electric marketplace. The ISO, under the
jurisdiction of the Federal Energy Regulatory Commission (FERC), oversees
California's electric transmission grid to ensure that all generators have
comparable access and that the reliability of the system is maintained.
California utilities retained ownership of utility transmission facilities,
but relinquished operating control to the ISO. Starting March 31, 1998, the
ISO has scheduled the delivery of resources such as Qualifying Facilities
(QFs) and Diablo Canyon Nuclear Power Plant (Diablo Canyon). These
resources for operational or reliability reasons are considered "must-take"
units and operate under cost-of-service contracts. After scheduling must-
take resources, the ISO satisfies the remaining aggregate demand with
purchases from the PX and purchases of necessary generation and ancillary
services to maintain grid reliability. To meet the ISO's demand, the PX
accepts the lowest bids from competing electric providers, which establishes
a market price. Customers choosing to buy power directly from non-regulated
generators or retailers will pay for that generation based upon negotiated
contracts.
CPUC regulation requires the Utility to sell all of its generated
electric power and must-take electric power purchased from external power
producers to the PX. The Utility must then purchase all electric power for
its retail customers from the PX. For the three- and nine-month periods
ended September 30, 1998, the Cost of energy for utility, reflected on the
Statement of Consolidated Income, is comprised of the cost of PX purchases,
ancillary services purchased from the ISO, and the cost of Utility
generation, net of sales to the PX (in millions) as follows:
For the three- For the nine-
months ended months ended
September 30, 1998 September 30, 1998
------------------ ------------------
Cost of electric generation 576 1,566
Cost of purchases from the PX 379 489
Net cost of ancillary services 130 169
Proceeds from sales to the PX (422) (608)
------ ------
Cost of electric energy 663 1,616
Utility cost of gas 51 333
------ ------
Cost of energy for Utility 714 1,949
Electric Transition Plan:
- -------------------------
In developing state legislation to implement a competitive market, involved
parties believed that the Utility's market-based revenues would not be
sufficient to recover (that is, to collect from customers) all generation
costs. Many of these costs resulted from past CPUC decisions. To recover
these uneconomic costs, called transition costs, and to ensure a smooth
transition to the competitive environment, a transition plan was developed
in the form of state legislation to position California for the new market
environment. The California legislature passed the legislation and the
Governor signed it in 1996. As discussed below in California Voter
Initiative, on November 3, 1998, Californians will vote on Proposition 9,
which would overturn major portions of the current electric utility
<PAGE>
restructuring legislation and would have a material adverse impact on the
Utility and the Corporation.
There are two principal elements of the transition plan established by
the restructuring legislation: (1) an electric rate freeze and rate
reduction; and (2) recovery of transition costs. Both of these elements are
discussed below. The restructuring legislation transition period ends
December 31, 2001. At the conclusion of the transition period, the Utility
will be at risk to recover any of its remaining generation costs through
market-based revenues.
Rate Freeze and Rate Reduction:
- -------------------------------
During 1997, electric rates for the Utility's customers were held at 1996
levels. Effective January 1, 1998, the Utility reduced electric rates for
its residential and small commercial customers by 10 percent and will hold
their rates at that level throughout the transition period. All other
electric customers' rates remained frozen at 1996 levels. The rate freeze
will continue until the end of the transition period. For the three- and
nine-month periods ended September 30, 1998, the 10 percent electric rate
reduction caused operating revenues to decrease by approximately $124
million and $304 million, respectively, as compared to the same periods in
1997.
As authorized by the restructuring legislation, to pay for the 10 percent
rate reduction, the Utility refinanced $2.9 billion of its transition costs
with rate reduction bonds, which have maturities ranging from three months
to ten years. The bonds defer recovery of a portion of the transition costs
until after the transition period. Pending the outcome of Proposition 9,
the Utility expects to recover the transition costs associated with the rate
reduction bonds over the term of the bonds.
Transition Cost Recovery:
- -------------------------
Transition costs are costs considered unavoidable and not expected to be
recovered through market-based revenues. These costs include: (1) the
above-market cost of Utility-owned generation facilities; (2) costs
associated with the Utility's long-term contracts to purchase power at
above-market prices from QFs and other power suppliers; and (3) generation-
related regulatory assets and obligations. (Regulatory assets are expenses
deferred in the current or prior periods to be included in rates in future
periods.)
The costs of Utility-owned generation facilities currently are included
in the Utility customers' rates. Above-market facility costs result when
book value is in excess of market value. Conversely, below-market facility
costs result when market value is in excess of book value. The total amount
of generation facility costs to be included as transition costs will be
based on the aggregate of above-market and below-market values. The above-
market portion of these costs is eligible for recovery as a transition cost.
The below-market portion of these costs will reduce other unrecovered
transition costs. A valuation of a Utility-owned generation facility where
the market value exceeds the book value could result in a material charge if
the valuation of the facility is determined based upon any method other than
a sale of the facility to a third party. This is because any excess of
market value over book value would be used to reduce other transition costs,
without increasing the book value of the plant assets.
The Utility will not be able to determine the exact amount of generation
facility costs that will be recoverable as transition costs until a market
valuation process (appraisal or sale) is completed for each of the Utility's
generation facilities. The first of these valuations occurred on July 1,
1998, when the Utility sold three Utility-owned electric generation plants
<PAGE>
for $501 million. (See Utility Generation Divestiture, below.) For
generation facilities that the Utility has not divested, the CPUC will
approve the methodology to be used in the market valuation process.
The above-market portion of costs associated with the Utility's long-term
contracts to purchase power at above-market prices from QFs and other power
suppliers also are eligible to be recovered as transition costs. The
Utility has agreed to purchase electric power from these suppliers under
long-term contracts expiring on various dates through 2028. Over the life
of these contracts, the Utility estimates that it will purchase
approximately 345 million megawatt-hours at an aggregate average price of
6.5 cents per kilowatt-hour. To the extent that this price is above the
market price, the Utility expects to collect the difference between the
contract price and the market price from customers, as a transition cost,
over the terms of the contracts.
Generation-related regulatory assets, net of regulatory obligations, also
are eligible for transition cost recovery. As of September 30, 1998, the
Utility has accumulated approximately $6.0 billion of these assets net of
certain obligations, including the amounts reclassified from Property,
plant, and equipment, discussed in Utility Generation Impairment below.
The restructuring legislation specifies that the Utility must recover
most transition costs by December 31, 2001. This recovery period is
significantly shorter than the recovery period of the related assets prior
to restructuring. Effective January 1, 1998, as authorized by the CPUC in
consideration of the restructuring legislation, the Utility is recording
amortization of most generation-related regulatory assets over the
transition period. The CPUC believes that the shortened recovery period
reduces risks associated with recovery of all the Utility's generation
assets, including Diablo Canyon and hydroelectric facilities. Accordingly,
the Utility is receiving a reduced return for all of its Utility-owned
generation facilities. In 1998, the reduced return on common equity for
these facilities is 6.77 percent.
Although the Utility must recover most transition costs by December 31,
2001, certain transition costs may be included in customers' electric rates
after the transition period. These costs include: (1) certain employee-
related transition costs; (2) above-market payments under existing QF and
power-purchase contracts discussed above; and (3) unrecovered electric
industry restructuring implementation costs. In addition, transition costs
financed by the issuance of rate reduction bonds are expected to be
recovered over the term of the bonds through the collection of the Fixed
Transition Amount (FTA) charge from customers. Further, the Utility's
nuclear decommissioning costs are being recovered through a CPUC-authorized
charge, which will extend until sufficient funds exist to decommission
Diablo Canyon and Humboldt Nuclear Power Plants. During the rate freeze,
the FTA and nuclear decommissioning charges will not increase the Utility
customers' electric rates. Excluding these specific items, the Utility will
write off any transition costs not recovered during the transition period.
Effective January 1, 1998, the Utility has been collecting eligible
transition costs through a CPUC-authorized nonbypassable charge called the
competition transition charge (CTC). The amount of revenue collected from
frozen rates for recovery of transition costs is subject to seasonal
fluctuations in the Utility's sales volumes. Revenues available for the
purpose of recovering transition costs exceeded transition cost expense for
the three-month period ended September 30, 1998, by $154 million. During
the nine-month period ended September 30, 1998, transition cost expense
exceeded associated revenues available for recovery of transition costs by
$349 million. In accordance with CPUC rate treatment of transition costs,
the Utility deferred this excess as a regulatory asset. The Utility expects
to recover this regulatory asset during the remainder of the transition
period.
<PAGE>
During the transition period, the CPUC will review the accounting methods
used by the Utility to recover transition costs and the amount of transition
costs requested for recovery. The CPUC is currently reviewing non-nuclear
transition costs amortized in the first half of 1998. The Utility expects
the CPUC to issue decisions regarding these reviews in the second quarter of
1999. At this time, the amount of transition cost disallowances, if any,
cannot be predicted.
In addition, on August 31, 1998, an independent accounting firm retained
by the CPUC completed its financial verification audit of the Utility's
Diablo Canyon plant accounts at December 31, 1996. The audit resulted in
the issuance of an unqualified opinion. The audit verified that Diablo
Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1
billion construction costs. (Sunk costs are costs associated with Utility-
owned generating facilities that are fixed and unavoidable and currently
included in the Utility customers' electric rates.) The independent
accounting firm also issued an agreed-upon special procedures report,
requested by the CPUC, which questioned $200 million of the $3.3 billion
sunk costs. The CPUC will review any proposed adjustments to Diablo
Canyon's recoverable costs, which resulted from the report. At this time,
the amount of transition cost disallowances, if any, cannot be predicted.
The Utility's ability to recover its transition costs during the
transition period will be dependent on several factors. The primary factor
is whether voters approve and the courts uphold Proposition 9, which would
eliminate transition cost recovery with certain exceptions. If Proposition
9 is defeated, the factors that continue to affect the Utility's ability to
recover transition costs include: (1) the continued application of the
regulatory framework established by the CPUC and state legislation; (2) the
amount of transition costs ultimately approved for recovery by the CPUC; (3)
the market value of the Utility-owned generation facilities; (4) future
Utility sales levels; (5) future Utility fuel and operating costs; (6) the
extent to which the Utility's authorized revenues to recover distribution
costs are increased or decreased; and (7) the market price of electricity.
Utility Generation Divestiture:
- -------------------------------
As part of electric industry restructuring, the Utility decided to sell its
fossil-fueled generation facilities. If the voters approve Proposition 9
(see California Voter Initiative, below,) then the Utility may alter its
current divestiture plan.
On July 1, 1998, the Utility completed the sale of three electric
Utility-owned fossil-fueled generating plants to Duke Energy Power Services
Inc. (Duke) for $501 million. These three fossil-fueled plants had a
combined book value at July 1, 1998, of approximately $351 million and a
combined capacity of 2,645 MW. The three power plants are located at Morro
Bay, Moss Landing, and Oakland.
The Utility will continue to operate and maintain the plants under a two-
year operating and maintenance agreement. Additionally, the Utility will
retain the liability for required environmental remediation of any pre-
closing soil or groundwater contamination at these plants. Although the
Utility is retaining such environmental remediation liability, the Utility
does not expect any material impact on its or PG&E Corporation's financial
position or results of operations. See Note 4, Environmental Remediation,
below.
In July 1998, the Utility agreed with the City and County of San
Francisco to permanently close Hunters Point Power Plant when reliable
alternative electricity resources are operational. The CPUC approved this
agreement in October 1998, allowing the Utility to recover the existing book
value of Hunters Point and the plant's environmental remediation and
decommissioning costs. Hunters Point is a fossil-fueled plant with a
<PAGE>
generating capacity of 423 MW and a book value, including plant-related
regulatory assets, at September 30, 1998, of $33 million.
Subject to the outcome of Proposition 9, the Utility currently intends to
sell its fossil-fueled and geothermal facilities: Potrero, Pittsburg, Contra
Costa, and Geysers power plants. These fossil-fueled and geothermal
facilities have a combined generating capacity of 4,289 MW and a combined
book value at September 30, 1998, of approximately $592 million. The
Utility is scheduled to receive final bids to purchase these plants in
November 1998, and to complete the sale of these plants in 1999.
Any net gains from the sale of the Utility-owned fossil-fueled and
geothermal plants will be used to offset other transition costs. As a
result, the Utility does not believe the sales will have a material impact
on its results of operations.
In 1997, the Utility informed the CPUC that it does not intend to retain
its remaining 4,000 MW of hydroelectric facilities as part of the Utility.
These remaining facilities have a combined book value at September 30, 1998,
of approximately $1.6 billion. As discussed above, any method of
disposition of assets other than through sale to a third party could result
in a material charge to the extent that the market value, as determined by
the CPUC, is in excess of book value.
Utility Generation Impairment:
- ------------------------------
In the third quarter of 1997, the Emerging Issues Task Force (EITF) of the
Financial Accounting Standards Board reached a consensus on its issue No.
97-4, entitled "Deregulation of the Pricing of Electricity - Issues Related
to the Application of SFAS (Statement of Financial Accounting Standard) No.
71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises - Accounting for the Discontinuation of Application of
SFAS No. 71" (EITF 97-4), which provided authoritative guidance on the
applicability of SFAS No. 71 during the transition period. EITF 97-4
required the Utility to discontinue the application of SFAS No. 71 for the
generation portion of its operations as of July 24, 1997, the effective date
of EITF 97-4. EITF 97-4 requires that regulatory assets and liabilities
(both those in existence today and those created under the terms of the
transition plan established by the restructuring legislation) be allocated
to the portion of the business from which the source of the regulated cash
flows is derived.
Under the guidance of EITF 97-4 and SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," an impairment analysis was required of the generating assets no longer
subject to the guidance of SFAS No. 71. The Utility compared the cash flows
from all sources, including CTC revenues, to the cost of the generating
facilities and found that the assets were not impaired. During the second
quarter of 1998, the Staff of the Securities and Exchange Commission (SEC)
issued interpretive guidance regarding the application of EITF 97-4 and SFAS
No. 121. The guidance states that an impairment analysis should exclude CTC
revenues from the recovery stream. Under this interpretation, the Utility
performed the impairment analysis excluding CTC revenues and determined that
$3.9 billion of its generation facilities were impaired. Because the
Utility expects to recover the impaired assets as a transition cost under
the transition plan established by the restructuring legislation, discussed
above, the Utility recorded a regulatory asset for the impaired amounts as
required by EITF 97-4. Accordingly, at June 30, 1998, this amount was
reclassified from Property, Plant, and Equipment to Regulatory assets on the
accompanying balance sheets. In addition, prior year balances were
reclassified.
<PAGE>
California Voter Initiative:
- ----------------------------
On November 3, 1998, California voters will vote on Proposition 9, an
initiative supported by various consumer groups.
Proposition 9 would overturn major provisions of California's electric
industry restructuring legislation. Proposition 9 proposes to: (1) require
the Utility and the other California investor-owned utilities to provide a
10 percent rate reduction to their residential and small commercial
customers in addition to the 10 percent rate reduction mandated by the
electric restructuring legislation; (2) eliminate transition cost recovery
for nuclear generation plants and related assets and obligations (other than
reasonable decommissioning costs); (3) eliminate transition cost recovery
for non-nuclear generation plants and related assets and obligations (other
than costs associated with QFs), unless the CPUC finds that the utilities
would be deprived of the opportunity to earn a fair rate of return; and (4)
prohibit the collection of any customer charges necessary to pay principal
and interest on the rate reduction bonds or, if a court finds that such
prohibition is not legal, require that utility rates be reduced to fully
offset the cost of the customer surcharges.
If the voters approve Proposition 9, then legal challenges by the
California utilities and others, including the Utility, would ensue. The
Utility intends to vigorously challenge Proposition 9 as unconstitutional
and to seek an immediate stay of its provisions pending court review of the
merits of its challenge.
If Proposition 9 is approved, and if the Utility were unable to conclude
that it is probable that Proposition 9 ultimately would be found invalid,
then under applicable accounting principles the Utility would be required to
write off generation-related regulatory assets, which would no longer be
probable of recovery because of reductions in future revenues. The Utility
anticipates that such a write-off would range from a minimum of
approximately $2.2 billion pre-tax to a maximum of approximately $5.0
billion pre-tax. This pre-tax loss would result in an after-tax loss
ranging from $1.3 billion to $2.9 billion, or $3 to $8 per share. The
amount of the write-off is dependent on how the courts and regulatory
agencies interpret and apply the provisions of Proposition 9. The maximum
$2.9 billion write-off would represent 48% of the Utility's total common
stockholders' equity of $6.0 billion at September 30, 1998.
The $2.9 billion maximum after-tax loss would eliminate the Utility's
retained earnings of $2.2 billion at September 30, 1998, and the Utility
would be unable to meet certain capital-related regulatory and legal
conditions. In addition, this loss would reduce the common equity ratio of
the Utility's ratemaking capital structure from approximately 48% to
approximately 32%, which is below the 48% equity ratio mandated by the CPUC.
Such a loss would severely impair the Utility's ability to pay dividends to
its preferred shareholders and the Corporation's ability to pay dividends to
its common shareholders. Also, the Utility is concerned that its credit
rating could drop to low investment grade or even below investment grade.
This would immediately and substantially reduce the market value of the
Utility's $5.8 billion in debt securities, increase the cost of raising new
debt capital, and may preclude the use of certain financial instruments for
raising capital.
The duration and amount of the rate decrease contemplated by Proposition
9 is uncertain and, if Proposition 9 is approved, will be subject to
interpretation by the courts and regulatory agencies. However, if all
provisions of Proposition 9 ultimately are upheld against legal challenge
and interpreted in an adverse manner, the amount of the average earnings
reductions could be approximately $200 million per year, or over $16 million
per month, from now through 2001 (assuming rates are reduced to offset the
charges for the rate reduction bonds) and approximately $50 million per year
from 2002 (based on rates under current regulatory decisions, assuming such
<PAGE>
decisions are in effect after the latest date on which the rate freeze would
otherwise end) to 2007 (the longest maturity date of the rate reduction
bonds). The earnings reduction estimates depend on how the courts and
regulators interpret Proposition 9 and how future rate changes unrelated to
Proposition 9 (such as changes resulting from the General Rate Case
proceeding, discussed below) affect the Utility's electric revenues.
As discussed in Transition Cost Recovery, above, the Utility is
recovering most of its transition costs under a rate freeze through the
transition period, which ends by December 31, 2001. If Proposition 9 is
immediately implemented, even on a temporary basis pending judicial review,
then the Utility's opportunity to recover transition costs will be reduced
each month. Depending on market conditions, this reduction could amount to
as much as $115 million per month, on average.
In addition to the potential impacts on the Utility discussed above,
during any such litigation, Proposition 9 may adversely affect the secondary
market for the rate reduction bonds. Further, the collection of the FTA
charges necessary to pay the rate reduction bonds while the litigation is
pending would be precluded, unless an immediate stay is granted. Even if a
stay is granted immediately, there may be terms and conditions imposed in
connection with the stay that may adversely affect the cash flow for timely
interest payments on the rate reduction bonds. The failure to pay interest
when due could give rise to an event of default. Finally, if Proposition 9
is upheld against legal challenge, then the primary source for payments on
the rate reduction bonds would become unavailable and holders of the rate
reduction bonds could incur a loss of their investment.
NOTE 3: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES
The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust),
has outstanding 12 million shares of 7.90 percent 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 the Utility 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 the Utility with a
face value of approximately $309 million, an interest rate of 7.90 percent,
and a maturity date of 2025.
NOTE 4: COMMITMENTS AND CONTINGENCIES
Nuclear Insurance:
- ------------------
The Utility has insurance coverage for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited
(NEIL). Under these policies, if a nuclear generating facility suffers a
loss due to a prolonged accidental outage, then the Utility may be subject
to maximum retrospective assessments of $17 million (property damage) and $6
million (business interruption), in each case per policy period, in the
event losses exceed the resources of NEIL.
The Utility has purchased primary insurance of $200 million for public
liability claims resulting from a nuclear incident. Secondary financial
protection provides an additional $9.7 billion in coverage, which is
mandated by federal legislation. It provides for loss sharing among
utilities owning nuclear generating facilities if a costly incident occurs.
If a nuclear incident results in claims in excess of $200 million, then the
Utility may be assessed up to $176 million per incident, with payments in
each year limited to a maximum of $20 million per incident.
<PAGE>
Environmental Remediation:
- --------------------------
The Utility may be required to pay for environmental remediation at sites
where the Utility 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, power plant sites, and sites
used by the Utility for the storage or disposal of potentially hazardous
materials. Under CERCLA, the Utility may be responsible for remediation of
hazardous substances, even if the Utility did not deposit those substances
on the site.
The Utility records a liability when site assessments indicate
remediation is probable and a range of reasonably likely cleanup costs can
be estimated. The Utility reviews its remediation liability quarterly for
each identified site. The liability is an estimate of costs for site
investigations, remediation, operations and maintenance, monitoring, and
site closure. The remediation costs also reflect: (1) technology; (2)
enacted laws and regulations; (3) experience gained at similar sites; and
(4) the probable level of involvement and financial condition of other
potentially responsible parties. Unless there is a better estimate within
this range of possible costs, the Utility records the lower end of this
range.
The cost of the hazardous substance remediation ultimately undertaken by
the Utility is difficult to estimate. A change in the estimate may occur in
the near term due to uncertainty concerning the Utility's responsibility,
the complexity of environmental laws and regulations, and the selection of
compliance alternatives. The Utility had an accrued liability at September
30, 1998, of $282 million for hazardous waste remediation costs at
identified sites, including divested fossil-fueled power plants.
Environmental remediation at identified sites may be as much as $486 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. The Utility estimated this upper limit of the
range of costs using assumptions least favorable to the Utility, based upon
a range of reasonably possible outcomes. Costs may be higher if the Utility
is found to be responsible for cleanup costs at additional sites or expected
outcomes change.
Of the $282 million liability, discussed above, the Utility has recovered
$97 million and expects to recover $162 million in future rates.
Additionally, the Utility is seeking recovery of its costs from insurance
carriers and from other third parties as appropriate.
The Corporation believes the ultimate outcome of these matters will not
have a material impact on its or the Utility's financial position or results
of operations.
Legal Matters:
- --------------
Chromium Litigation
Several civil suits are pending against the Utility in various California
state courts. The suits seek an unspecified amount of compensatory and
punitive damages for alleged personal injuries and, in some cases, property
damage, resulting from alleged exposure to chromium in the vicinity of the
Utility's gas compressor stations at Hinkley, Kettleman, and Topock,
California. Two of these cases also name PG&E Corporation as a defendant.
Currently, there are claims pending on behalf of approximately 2,300
plaintiffs.
<PAGE>
The Utility is responding to the suits and asserting affirmative
defenses. The Utility will pursue appropriate legal defenses, including
statute of limitations or exclusivity of workers' compensation laws, and
factual defenses, including lack of exposure to chromium and the inability
of chromium to cause certain of the illnesses alleged.
The Corporation believes that the ultimate outcome of this matter will
not have a material impact on its or the Utility's financial position or
results of operations.
Texas Franchise Fee Litigation
In connection with PG&E Corporation's acquisition of Valero Energy
Corporation, now known as PG&E Gas Transmission, Texas Corporation (GTT),
GTT succeeded to the litigation described below.
GTT and various of its affiliates are defendants in at least two class
action suits and six separate suits filed by various Texas cities.
Generally, these cities allege, among other things, that: (1) owners or
operators of pipelines occupied city property and conducted pipeline
operations without the cities' consent and without compensating the cities;
and (2) the gas marketers failed to pay the cities for accessing and
utilizing the pipelines located in the cities to flow gas under city
streets. Plaintiffs also allege various other claims against the defendants
for failure to secure the cities' consent. Damages are not quantified.
In June 1998, a jury trial began in the case brought by the City of
Edinburg, on its own behalf and not as a class action, which involved, among
other things, a particular franchise agreement entered into by a former
subsidiary of GTT (now owned by Southern Union Gas Company (SU)) and the
City and certain conduct of the defendants. In August 1998, the jury
returned a verdict in favor of the City and awarded actual damages in the
approximate aggregate amount of $9.8 million, plus attorneys' fees of
approximately $3.5 million against GTT, SU and various affiliates. The jury
refused to award punitive damages against the GTT defendants. A hearing on
the plaintiff's motion for entry of judgment has been scheduled for December
1, 1998, after which the court will enter a judgment. At the hearing, the
court may provide guidance as to how the damages and attorneys' fees of
approximately $13.3 million will be apportioned among the parties. If an
adverse judgment is entered, GTT and its various subsidiaries intend to
appeal the judgment.
The Corporation believes that the ultimate outcome of these matters will
not have a material impact on its financial position or results of
operation.
ITEM 2. MANAGEMENT's DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF
OPERATIONS AND FINANCIAL CONDITION
San Francisco-based PG&E Corporation provides integrated energy services.
PG&E Corporation's consolidated financial statements include the accounts of
PG&E Corporation and its various business lines:
- -Pacific Gas and Electric Company (Utility)
- -Unregulated Business Operations consisting of:
- Gas Transmission through PG&E Gas Transmission;
- Electric Generation through U.S. Generating Company (USGen);
- Energy Commodities and Services through PG&E Energy Trading
and PG&E Energy Services.
<PAGE>
Overview:
- ---------
This is a combined Quarterly Report Form 10-Q of PG&E Corporation and
Pacific Gas and Electric Company. Therefore, our Management's Discussion
and Analysis of Consolidated Results of Operations and Financial Condition
(MD&A) applies to both PG&E Corporation and the Utility. PG&E Corporation's
consolidated financial statements include the accounts of PG&E Corporation
and its wholly owned and controlled subsidiaries, including the Utility
(collectively, the Corporation). Our Utility's consolidated financial
statements include its accounts as well as those of its wholly owned and
controlled subsidiaries. This MD&A should be read in conjunction with the
consolidated financial statements included herein. Further, this quarterly
report should be read in conjunction with the Corporation's and the
Utility's Consolidated Financial Statements and Notes to Consolidated
Financial Statements incorporated by reference in their combined 1997 Annual
Report on Form 10-K.
In this MD&A, we explain the results of operations for the three- and
nine-month periods ended September 30, 1998, as compared to the
corresponding periods in 1997, and discuss our financial condition. Our
discussion of financial condition includes:
- - changes in the energy industry and how we expect these changes to
influence future results of operations;
- - liquidity and capital resources, including discussions of capital
financing activities, and uncertainties that could affect future results;
and
- - risk management activities.
This Quarterly Report Form 10-Q, including our discussion of results of
operations and financial condition below, contains forward-looking
statements that involve risks and uncertainties. These statements are based
on the beliefs and assumptions of management and on information currently
available to management. Words such as "estimates," "expects,"
"anticipates," "plans," "believes," and similar expressions identify
forward-looking statements involving risks and uncertainties. Actual
results may differ materially from those expressed in the forward-looking
statements.
The most important factor that could affect future results and that would
cause actual results to differ materially from those expressed in the
forward looking statements, or from historical results, is the outcome and
potential impact of Proposition 9. If the voters approve and the courts
uphold Proposition 9, then Proposition 9 would overturn major provisions of
California's electric industry restructuring legislation. Other important
factors include, but are not limited to: (1) the ongoing restructuring of
the electric and gas industries in California and nationally; (2) the
outcome of the regulatory proceedings related to the restructuring; (3) the
Utility's ability to collect revenues sufficient to recover transition costs
in accordance with its transition cost recovery plan, specifically in light
of Proposition 9; (4) the planned sale of the Utility-owned fossil-fueled
electric generating plants, which may be altered if the voters approve
Proposition 9; (5) the impact of, and our ability to successfully integrate,
our acquisitions, including the New England Electric System (NEES) and the
Texas assets; (6) the potential impact from internal or external Year 2000
problems; (7) the outcome of the Utility's Cost of Capital proceeding; (8)
approval of the Utility's 1999 General Rate Case application providing the
Utility the opportunity to earn its authorized rate of return; (9) increased
competition; (10) our ability to expand into and to compete successfully in
new markets as the passage of Proposition 9 may stall electric industry
restructuring nationally; and (11) fluctuations in the prices of commodity
gas and electricity and our ability to successfully hedge against such price
risk. We discuss each of these items in greater detail below.
<PAGE>
RESULTS OF OPERATIONS
In this section, we provide the components of our earnings for the three-
and nine-month periods ended September 30, 1998, and 1997. We then explain
why operating revenues and expenses varied from 1998 to 1997.
The following table shows results of operations for the three- and nine-
month periods ended September 30, 1998, and 1997, and total assets at
September 30, 1998, and 1997. The results for unregulated business
operations include the Corporation on a stand-alone basis.
<TABLE>
(in millions)
<CAPTION>
Unregulated
Business Elimin-
Utility Operations ations Total
-------- ------------ ------- -------
<S> <C> <C> <C> <C>
For the three months ended
September 30,
1998
Operating revenues $ 2,563 $ 2,930 $ (186) $ 5,307
Operating expenses 2,037 2,914 (186) 4,765
------- ------- ------ -------
Operating income 526 16 - 542
Income available for
common stock 199 11 - 210
1997
Operating revenues $ 2,541 $ 1,565 $ (43) $ 4,063
Operating expenses 1,915 1,563 (43) 3,435
------- ------- ------- -------
Operating income 626 2 - 628
Income available for
common stock 269 (12) - 257
For the nine months ended
September 30,
1998
Operating revenues $ 6,706 $ 8,263 $ (522) $14,447
Operating expenses 5,257 8,145 (522) 12,880
------- ------- ------ -------
Operating income 1,449 118 - 1,567
Income available for
common stock 533 (10) - 523
Total assets at September 30 $22,468 $ 9,577 $ (347) $31,698
1997
Operating revenues $ 7,094 $ 3,485 $ (68) $10,511
Operating expenses 5,653 3,463 (68) 9,048
------- ------- ------- -------
Operating income 1,441 22 - 1,463
Income available for
common stock 554 68 - 622
Total assets at September 30 $23,895 $ 5,903 $ (383) $29,415
</TABLE>
Common Stock Dividend:
- ----------------------
We base our common stock dividend on a number of financial considerations,
including sustainability, financial flexibility, and competitiveness with
investment opportunities of similar risk. Our current quarterly common
stock dividend is $.30 per common share, which corresponds to an annualized
dividend of $1.20 per common share.
<PAGE>
The California Public Utility Commission (CPUC) requires the Utility to
maintain its CPUC-authorized capital structure, potentially limiting the
amount of dividends the Utility may pay the Corporation. At September 30,
1998, the Utility was in compliance with its CPUC-authorized capital
structure. The Utility believes that it will continue to meet this
condition in the future without affecting the Corporation's ability to pay
common stock dividends. However, if the voters approve and the courts
uphold Proposition 9, then the Utility would be required to write off
generation-related regulatory assets. Such a loss would severely impair the
Corporation's ability to pay dividends to its common shareholders.
Earnings Per Common Share:
- --------------------------
Earnings per common share for the three- and nine-month periods ended
September 30, 1998, decreased $.07 and $.16 cents, respectively, as compared
to the same periods in 1997. The activity discussed below affected earnings
per common share.
Utility Results:
- ----------------
Utility operating revenues increased $22 million for the three-month period
and decreased $388 million for the nine-month period ended September 30,
1998, as compared to the same periods in 1997. Operating revenues for the
three-month period ended September 30, 1998, increased primarily due to the
termination of our volumetric (ERAM) and energy cost (ECAC) revenue
balancing account, which reduced revenues by $122 million in 1997. This
increase is offset by lower billed revenues due to the 10% rate reduction
and reduced sales volumes. (The Utility replaced the ERAM and ECAC
balancing accounts with the transition cost balancing account (TCBA), which
impacts expenses instead of revenues as discussed in Transition Cost
Recovery, below.) Operating revenues for the nine-month period ended
September 30, 1998, decreased due to: (1) a 10 percent electric rate
reduction, discussed below, provided to residential and small commercial
customers, which caused a decrease of $124 million and $304 million for the
three- and nine-month periods ended September 30, 1998, respectively; (2) a
decrease in sales to medium and large electric customers, many of whom are
now purchasing their electricity directly from unregulated power generators;
and (3) a decrease in usage and sales to commercial and agricultural
electric customers resulting from their lower demand for irrigation water
pumping as a result of heavier rainfall in the current year.
Utility operating expenses increased $122 million for the three-month
period and decreased $396 million for the nine-month period ended September
30, 1998, as compared to the same periods in 1997. Operating expenses for
the nine-month period ended September 30, 1998, declined primarily as a
result of; (1) decreased fuel costs at power plants, primarily due to plant
sales; (2) decreased costs associated with Qualifying Facilities (QFs) due
to the expiration of the fixed price periods in many QF contracts; (3) lower
transmission pipeline demand charges; and (4) expense deferrals related to
electric industry restructuring. Increased expenses incurred for system
reliability and accelerated amortization of regulatory assets recovered
under the transition plan established by the restructuring legislation
partially offset these decreases. As previously indicated, electric
industry restructuring provides for recovery of certain costs in future
periods. Some costs, associated with the expense deferrals mentioned above,
will be recovered as electric sales volumes increase during seasonal
fluctuations. Others relate to transition costs, which will be recovered
over the term of the rate reduction bonds.
<PAGE>
Unregulated Business Results:
- -----------------------------
Our unregulated business operations include those business activities that
are not directly regulated by the CPUC. Unregulated business operating
revenues for the three- and nine-month periods ended September 30, 1998,
increased approximately $1.4 billion and $4.8 billion, respectively, while
operating expenses increased approximately $1.4 billion and $4.7 billion,
respectively, as compared to the same periods in 1997. These increases were
due to operations associated with our energy commodities and services
activities and due to the acquisition of the natural gas operations of
Valero Energy Corporation in July 1997. Energy trading volumes continue to
increase over 1997 levels. The resultant operating revenue increases from
these activities, however, were partially offset by decreases in our Texas
operations from: (1) low natural gas transmission prices and volumes; and
(2) low differentials between natural gas liquids prices and the cost of
natural gas.
Unregulated business operations contributed $23 million more in net
income for the three-month period ended September 30, 1998, than in the same
period in 1997, and $78 million less in net income in the nine-month period
ended September 30, 1998, than in the same periods in 1997. The decrease
for the nine-month period ended September 30, 1998, is due to the loss on
sale of our Australian holdings (See Acquisitions and Sales, below.) The
decrease was also due to the $110 million gain that the Corporation
recognized in the second quarter 1997 on the sale of its interest in
International Generating Company, Ltd. The second quarter 1997 gain was
partially offset by write-downs of certain unregulated investments of
approximately $41 million.
FINANCIAL CONDITION
We begin this section by discussing the energy industry. We also discuss
how we are responding to restructuring on a national level, including a
recent acquisition. We then discuss liquidity and capital resources and our
risk management activities.
COMPETITION AND CHANGING REGULATORY ENVIRONMENT:
The Utility Electric Generation Business:
On March 31, 1998, California became one of the first states in the country
to allow open competition in the electric generation business. Today, many
Californians may choose an energy service provider, which will provide their
electric power generation. The Utility's customers may choose to purchase
electricity: (1) from the Utility; (2) from retail electricity providers
(for example, marketers including our energy service subsidiary, brokers,
and aggregators); or (3) directly from unregulated power generators. Our
Utility expects to continue to provide distribution services to
substantially all electric consumers within its service territory.
Competitive Market Framework:
- -----------------------------
To create the competitive generation market, California has established a
Power Exchange (PX) and an Independent Systems Operator (ISO). The PX sets
electricity prices in an open electric marketplace. The ISO, under the
jurisdiction of the Federal Energy Regulatory Commission (FERC), oversees
California's electric transmission grid to ensure that all generators have
comparable access and that the reliability of the system is maintained.
California utilities retained ownership of utility transmission facilities,
but relinquished operating control to the ISO. Starting March 31, 1998, the
ISO has scheduled the delivery of resources such as Qualifying Facilities
<PAGE>
(QFs) and Diablo Canyon. These resources for operational or reliability
reasons are considered "must-take" units and operate under cost-of-service
contracts. After scheduling must-take resources, the ISO satisfies the
remaining aggregate demand with purchases from the PX and purchases of
necessary generation and ancillary services to maintain grid reliability.
To meet the ISO's demand, the PX accepts the lowest bids from competing
electric providers, which establishes a market price. Customers choosing to
buy power directly from non-regulated generators or retailers will pay for
that generation based upon negotiated contracts.
CPUC regulation requires the Utility to sell all of its generated
electric power and must-take electric power purchased from external power
producers to the PX. The Utility must then purchase all electric power for
its retail customers from the PX. For the three- and nine-month periods
ended September 30, 1998, the Cost of energy for utility, reflected on the
Statement of Consolidated Income, is comprised of the cost of PX purchases,
ancillary services purchased from the ISO, and the cost of Utility
generation, net of sales to the PX (in millions) as follows:
For the three- For the nine-
months ended months ended
September 30, 1998 September 30, 1998
------------------ ------------------
Cost of electric generation 576 1,566
Cost of purchases from the PX 379 489
Net cost of ancillary services 130 169
Proceeds from sales to the PX (422) (608)
------ ------
Cost of electric energy 663 1,616
Utility cost of gas 51 333
------ ------
Cost of energy for Utility 714 1,949
Electric Transition Plan:
- -------------------------
Over the past several years, we have taken steps to prepare for competition
in the electric generation business. We have worked with the CPUC to ensure
a smooth transition into the competitive market environment. In addition,
we have made strategic investments throughout the nation that will further
position us as a national energy provider.
In developing state legislation to implement a competitive market,
involved parties believed that our Utility's market-based revenues would not
be sufficient to recover (that is, to collect from customers) all generation
costs. Many of these costs resulted from past CPUC decisions. To recover
these uneconomic costs, called transition costs, and to ensure a smooth
transition to the competitive environment, a transition plan was developed
in the form of state legislation to position California for the new market
environment. The California Legislature passed the legislation and the
Governor signed it in 1996. As discussed below in California Voter
Initiative, on November 3, 1998, Californians will vote on Proposition 9,
which would overturn major portions of the current electric utility
restructuring legislation and would have a material adverse impact on the
Utility and the Corporation.
There are two principal elements of the transition plan established by
restructuring legislation: (1) an electric rate freeze and rate reduction;
and (2) recovery of transition costs. Both of these elements, and the
impact of the approved transition plan on our Utility's customers, are
discussed below. The restructuring legislation transition period ends
December 31, 2001. At the conclusion of the transition period, we will be
at risk to recover any of our Utility's remaining generation costs through
market-based revenues.
<PAGE>
Rate Freeze and Rate Reduction:
- -------------------------------
During 1997, electric rates for our Utility's customers were held at 1996
levels. Effective January 1, 1998, the Utility reduced electric rates for
its residential and small commercial customers by 10 percent and will hold
their rates at that level throughout the transition period. All other
electric customers' rates remained frozen at 1996 levels. The rate freeze
will continue until the end of the transition period. For the three- and
nine-month periods ended September 30, 1998, the 10 percent rate reduction
caused operating revenues to decrease by approximately $124 million and $304
million, respectively, as compared to the same periods in 1997.
As authorized by the restructuring legislation, to pay for the 10 percent
rate reduction, the Utility refinanced $2.9 billion of its transition costs
with rate reduction bonds, which have maturities ranging from three months
to ten years. The bonds defer recovery of a portion of the transition costs
until after the transition period. Pending the outcome of Proposition 9,
the Utility expects to recover the transition costs associated with the rate
reduction bonds over the term of the bonds.
Transition Cost Recovery:
- -------------------------
Transition costs are costs considered unavoidable and not expected to be
recovered through market-based revenues. These costs include: (1) the
above-market cost of Utility-owned generation facilities; (2) costs
associated with the Utility's long-term contracts to purchase power at
above-market prices from QFs and other power suppliers; and (3) generation-
related regulatory assets and obligations. (Regulatory assets are expenses
deferred in the current or prior periods to be included in rates in future
periods.)
The costs of Utility-owned generation facilities currently are included
in the Utility customers' rates. Above-market facility costs result when
book value is in excess of market value. Conversely, below-market facility
costs result when market value is in excess of book value. The total amount
of generation facility costs to be included as transition costs will be
based on the aggregate of above-market and below-market values. The above-
market portion of these costs is eligible for recovery as a transition cost.
The below-market portion of these costs will reduce other unrecovered
transition costs. A valuation of a Utility-owned generation facility where
the market value exceeds the book value could result in a material charge if
the valuation of the facility is determined based upon any method other than
a sale of the facility to a third party. This is because any excess of
market value over book value would be used to reduce other transition costs,
without increasing the book value of the plant assets.
The Utility will not be able to determine the exact amount of generation
facility costs that will be recoverable as transition costs until a market
valuation process (appraisal or sale) is completed for each of the Utility's
generation facilities. The first of these valuations occurred on July 1,
1998, when the Utility sold three Utility-owned electric generation plants
for $501 million. (See Utility Generation Divestiture, below.) For
generation facilities that the Utility has not divested, the CPUC will
approve the methodology to be used in the market valuation process.
The above-market portion of costs associated with the Utility's long-term
contracts to purchase power at above-market prices from QFs and other power
suppliers also are eligible to be recovered as transition costs. The
Utility has agreed to purchase electric power from these suppliers under
long-term contracts expiring on various dates through 2028. Over the life
of these contracts, the Utility estimates that it will purchase
approximately 345 million megawatt-hours at an aggregate average price of
<PAGE>
6.5 cents per kilowatt-hour. To the extent that this price is above the
market price, the Utility expects to collect the difference between the
contract price and the market price from customers, as a transition cost,
over the terms of the contracts.
Generation-related regulatory assets, net of regulatory obligations, also
are eligible for transition cost recovery. As of September 30, 1998, the
Utility has accumulated approximately $6.0 billion of these assets net of
certain obligations, including the amounts reclassified from Property,
plant, and equipment, discussed in Utility Generation Impairment below.
The restructuring legislation specifies that the Utility must recover
most transition costs by December 31, 2001. This recovery period is
significantly shorter than the recovery period of the related assets prior
to restructuring. Effective January 1, 1998, as authorized by the CPUC in
consideration of the restructuring legislation, the Utility is recording
amortization of most generation-related regulatory assets over the
transition period. The CPUC believes that the shortened recovery period
reduces risks associated with recovery of all the Utility's generation
assets, including Diablo Canyon and hydroelectric facilities. Accordingly,
the Utility is receiving a reduced return for all of its Utility-owned
generation facilities. In 1998, the reduced return on common equity for
these facilities is 6.77 percent.
Although the Utility must recover most transition costs by December 31,
2001, certain transition costs may be included in customers' electric rates
after the transition period. These costs include: (1) certain employee-
related transition costs; (2) above-market payments under existing QF and
power-purchase contracts discussed above; and (3) unrecovered electric
industry restructuring implementation costs. In addition, transition costs
financed by the issuance of rate reduction bonds are expected to be
recovered over the term of the bonds through the collection of the Fixed
Transition Amount (FTA) charge from customers. Further, the Utility's
nuclear decommissioning costs are being recovered through a CPUC-authorized
charge, which will extend until sufficient funds exist to decommission
Diablo Canyon and Humboldt Nuclear Power Plants. During the rate freeze,
the FTA and nuclear decommissioning charges will not increase the Utility
customers' electric rates. Excluding these specific items, the Utility will
write off any transition costs not recovered during the transition period.
Effective January 1, 1998, the Utility has been collecting eligible
transition costs through a CPUC-authorized nonbypassable charge called the
competition transition charge (CTC). The amount of revenue collected from
frozen rates for recovery of transition costs is subject to seasonal
fluctuations in the Utility's sales volumes. Revenues available for the
purpose of recovering transition costs exceeded transition cost expense for
the three-month period ended September 30, 1998, by $154 million. During
the nine-month period ended September 30, 1998, transition cost expense
exceeded associated revenues available for recovery of transition costs by
$349 million. In accordance with CPUC rate treatment of transition costs,
the Utility deferred this excess as a regulatory asset. The Utility expects
to recover this regulatory asset during the remainder of the transition
period.
During the transition period, the CPUC will review the accounting methods
used by the Utility to recover transition costs and the amount of transition
costs requested for recovery. The CPUC is currently reviewing non-nuclear
transition costs amortized in the first half of 1998. The Utility expects
the CPUC to issue decisions regarding these reviews in the second quarter of
1999. At this time, the amount of transition cost disallowances, if any,
cannot be predicted.
In addition, on August 31, 1998, an independent accounting firm retained
by the CPUC completed its financial verification audit of the Utility's
Diablo Canyon plant accounts at December 31, 1996. The audit resulted in
<PAGE>
the issuance of an unqualified opinion. The audit verified that Diablo
Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1
billion construction costs. (Sunk costs are costs associated with Utility-
owned generating facilities that are fixed and unavoidable and currently
included in the Utility customers' electric rates.) The independent
accounting firm also issued an agreed-upon special procedures report,
requested by the CPUC, which questioned $200 million of the $3.3 billion
sunk costs. The CPUC will review any proposed adjustments to Diablo
Canyon's recoverable costs, which resulted from the report. At this time,
the amount of transition cost disallowances, if any, cannot be predicted.
The Utility's ability to recover its transition costs during the
transition period will be dependent on several factors. The primary factor
is whether voters approve and the courts uphold Proposition 9, which would
eliminate transition cost recovery with certain exceptions. If Proposition
9 is defeated, the factors that continue to affect the Utility's ability to
recover transition costs include: (1) the continued application of the
regulatory framework established by the CPUC and state legislation; (2) the
amount of transition costs ultimately approved for recovery by the CPUC; (3)
the market value of the Utility-owned generation facilities; (4) future
Utility sales levels; (5) future Utility fuel and operating costs; (6) the
extent to which the Utility's authorized revenues to recover distribution
costs are increased or decreased; and (7) the market price of electricity.
Utility Generation Divestiture:
- -------------------------------
As part of electric industry restructuring, the Utility decided to sell its
fossil-fueled generation facilities. If the voters approve Proposition 9
(see California Voter Initiative, below,) then the Utility may alter its
current divestiture plan.
On July 1, 1998, the Utility completed the sale of three electric
Utility-owned fossil-fueled generating plants to Duke Energy Power Services
Inc. (Duke) for $501 million. These three fossil-fueled plants had a
combined book value at July 1, 1998, of approximately $351 million and a
combined capacity of 2,645 MW. The three power plants are located at Morro
Bay, Moss Landing, and Oakland.
The Utility will continue to operate and maintain the plants under a two-
year operating and maintenance agreement. Additionally, the Utility will
retain the liability for required environmental remediation of any pre-
closing soil or groundwater contamination at these plants. Although the
Utility is retaining such environmental remediation liability, the Utility
does not expect any material impact on its or PG&E Corporation's financial
position or results of operations.
In July 1998, the Utility agreed with the City and County of San
Francisco to permanently close Hunters Point Power Plant when reliable
alternative electricity resources are operational. The CPUC approved this
agreement in October 1998, allowing the Utility to recover the existing book
value of Hunters Point and the plant's environmental remediation and
decommissioning costs. Hunters Point is a fossil-fueled plant with a
generating capacity of 423 MW and a book value, including plant-related
regulatory assets, at September 30, 1998, of $33 million.
Subject to the outcome of Proposition 9, the Utility currently intends to
sell its fossil-fueled and geothermal facilities: Potrero, Pittsburg, Contra
Costa, and Geysers power plants. These fossil-fueled and geothermal
facilities have a combined generating capacity of 4,289 MW and a combined
book value at September 30, 1998, of approximately $592 million. The
Utility is scheduled to receive final bids to purchase these plants in
November 1998, and to complete the sale of these plants in 1999.
<PAGE>
Any net gains from the sale of our Utility-owned fossil-fueled and
geothermal plants will be used to offset other transition costs. As a
result, we do not believe the sales will have a material impact on our
results of operations.
In 1997, the Utility informed the CPUC that it does not intend to retain
its remaining 4,000 MW of hydroelectric facilities as part of the Utility.
These remaining facilities have a combined book value at September 30, 1998,
of approximately $1.6 billion. As discussed above, any method of
disposition of assets other than through sale to a third party could result
in a material charge to the extent that the market value, as determined by
the CPUC, is in excess of book value.
Utility Generation Impairment:
- ------------------------------
In the third quarter of 1997, the Emerging Issues Task Force (EITF) of the
Financial Accounting Standards Board reached a consensus on its issue No.
97-4, entitled "Deregulation of the Pricing of Electricity - Issues Related
to the Application of SFAS (Statement of Financial Accounting Standard) No.
71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises - Accounting for the Discontinuation of Application of
SFAS No. 71" (EITF 97-4), which provided authoritative guidance on the
applicability of SFAS No. 71 during the transition period. EITF 97-4
required the Utility to discontinue the application of SFAS No. 71 for the
generation portion of its operations as of July 24, 1997, the effective date
of EITF 97-4. EITF 97-4 requires that regulatory assets and liabilities
(both those in existence today and those created under the terms of the
transition plan established by the restructuring legislation) be allocated
to the portion of the business from which the source of the regulated cash
flows is derived.
Under the guidance of EITF 97-4 and SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," an impairment analysis was required of the generating assets no longer
subject to the guidance of SFAS No. 71. The Utility compared the cash flows
from all sources, including CTC revenues, to the cost of the generating
facilities and found that the assets were not impaired. During the second
quarter of 1998, the Staff of the Securities and Exchange Commission (SEC)
issued interpretive guidance regarding the application of EITF 97-4 and SFAS
No. 121. The guidance states that an impairment analysis should exclude CTC
revenues from the recovery stream. Under this interpretation, the Utility
performed the impairment analysis excluding CTC revenues and determined that
$3.9 billion of its generation facilities were impaired. Because the
Utility expects to recover the impaired assets as a transition cost under
the transition plan established by the restructuring legislation, discussed
above, the Utility recorded a regulatory asset for the impaired amounts as
required by EITF 97-4. Accordingly, at June 30, 1998, this amount was
reclassified from Property, Plant, and Equipment to Regulatory assets on the
accompanying balance sheets. In addition, prior year balances were
reclassified.
Customer Impacts of Transition Plan:
- ------------------------------------
Effective March 31, 1998, all Californians may choose their electric
commodity provider. As of October 15, 1998, the Utility had accepted
approximately 63,000 requests to switch their electric commodity supplier
from the Utility to another electric commodity provider.
Regardless of the customer's choice of electric commodity provider,
during the transition period, customers will be billed for electricity used,
for transmission and distribution services, for public purpose programs, and
for recovery of transition costs. Customers who choose to purchase their
electricity from non-Utility energy providers will see a change in their
<PAGE>
total bill only to the extent that their contracted electric commodity price
differs from the PX price. Transition costs are being recovered from
substantially all Utility distribution customers through a nonbypassable
charge regardless of their choice in commodity provider. We do not believe
that the availability of choice to our customers will have a material impact
on our ability to recover transition costs.
In addition to supplying commodity electric power, commodity electric
providers may choose the method of billing their customers and whether to
provide their customers with metering services. We are tracking cost
savings that result when billing, metering, and related services within our
Utility's service territory are provided by another entity. Once these cost
savings, or credits, are approved by the CPUC and the customer's energy
provider is performing billing and metering services, we will: (1) refund
the savings to customers where the Utility provides the billing for these
services; or (2) remit the savings to the electric providers where the
electric provider bills for these services. The electric providers then
will charge their customers for these services. To the extent that these
credits equate to our actual cost savings from reduced billing, metering,
and related services, we do not expect a material impact on the
Corporation's or the Utility's financial condition or results of operations.
California Voter Initiative:
- ----------------------------
On November 3, 1998, California voters will vote on Proposition 9, an
initiative supported by various consumer groups.
Proposition 9 would overturn major provisions of California's electric
industry restructuring legislation. Proposition 9 proposes to: (1) require
the Utility and the other California investor-owned utilities to provide a
10 percent rate reduction to their residential and small commercial
customers in addition to the 10 percent rate reduction mandated by the
electric restructuring legislation; (2) eliminate transition cost recovery
for nuclear generation plants and related assets and obligations (other than
reasonable decommissioning costs); (3) eliminate transition cost recovery
for non-nuclear generation plants and related assets and obligations (other
than costs associated with QFs), unless the CPUC finds that the utilities
would be deprived of the opportunity to earn a fair rate of return; and (4)
prohibit the collection of any customer charges necessary to pay principal
and interest on the rate reduction bonds or, if a court finds that such
prohibition is not legal, require that utility rates be reduced to fully
offset the cost of the customer surcharges.
If the voters approve Proposition 9, then legal challenges by the
California utilities and others, including the Utility, would ensue. The
Utility intends to vigorously challenge Proposition 9 as unconstitutional
and to seek an immediate stay of its provisions pending court review of the
merits of its challenge.
If Proposition 9 is approved, and if the Utility were unable to conclude
that it is probable that Proposition 9 ultimately would be found invalid,
then under applicable accounting principles the Utility would be required to
write off generation-related regulatory assets, which would no longer be
probable of recovery because of reductions in future revenues. The Utility
anticipates that such a write-off would range from a minimum of
approximately $2.2 billion pre-tax to a maximum of approximately $5.0
billion pre-tax. This pre-tax loss would result in an after-tax loss
ranging from $1.3 billion to $2.9 billion, or $3 to $8 per share. The
amount of the write-off is dependent on how the courts and regulatory
agencies interpret and apply the provisions of Proposition 9. The maximum
$2.9 billion write-off would represent 48% of the Utility's total common
stockholders' equity of $6.0 billion at September 30, 1998.
<PAGE>
The $2.9 billion maximum after-tax loss would eliminate the Utility's
retained earnings of $2.2 billion at September 30, 1998, and the Utility
would be unable to meet certain capital-related regulatory and legal
conditions. In addition, this loss would reduce the common equity ratio of
the Utility's ratemaking capital structure from approximately 48% to
approximately 32%, which is below the 48% equity ratio mandated by the CPUC.
Such a loss would severely impair the Utility's ability to pay dividends to
its preferred shareholders and the Corporation's ability to pay dividends to
its common shareholders. Also, the Utility is concerned that its credit
rating could drop to low investment grade or even below investment grade.
This would immediately and substantially reduce the market value of the
Utility's $5.8 billion in debt securities, increase the cost of raising new
debt capital, and may preclude the use of certain financial instruments for
raising capital.
The duration and amount of the rate decrease contemplated by Proposition
9 is uncertain and, if Proposition 9 is approved, will be subject to
interpretation by the courts and regulatory agencies. However, if all
provisions of Proposition 9 ultimately are upheld against legal challenge
and interpreted in an adverse manner, the amount of the average earnings
reductions could be approximately $200 million per year, or over $16 million
per month, from now through 2001 (assuming rates are reduced to offset the
charges for the rate reduction bonds) and approximately $50 million per year
from 2002 (based on rates under current regulatory decisions, assuming such
decisions are in effect after the latest date on which the rate freeze would
otherwise end) to 2007 (the longest maturity date of the rate reduction
bonds). The earnings reduction estimates depend on how the courts and
regulators interpret Proposition 9 and how future rate changes unrelated to
Proposition 9 (such as changes resulting from the General Rate Case
proceeding, discussed below) affect the Utility's electric revenues.
As discussed in Transition Cost Recovery, above, the Utility is
recovering most of its transition costs under a rate freeze through the
transition period, which ends by December 31, 2001. If Proposition 9 is
immediately implemented, even on a temporary basis pending judicial review,
then the Utility's opportunity to recover transition costs will be reduced
each month. Depending on market conditions, this reduction could amount to
as much as $115 million per month, on average.
In addition to the potential impacts on the Utility discussed above,
during any such litigation, Proposition 9 may adversely affect the secondary
market for the rate reduction bonds. Further, the collection of the FTA
charges necessary to pay the rate reduction bonds while the litigation is
pending would be precluded, unless an immediate stay is granted. Even if a
stay is granted immediately, there may be terms and conditions imposed in
connection with the stay that may adversely affect the cash flow for timely
interest payments on the rate reduction bonds. The failure to pay interest
when due could give rise to an event of default. Finally, if Proposition 9
is upheld against legal challenge, then the primary source for payments on
the rate reduction bonds would become unavailable and holders of the rate
reduction bonds could incur a loss of their investment.
The Utility Electric Transmission Business:
Utility electric transmission revenues are under FERC jurisdiction. In
December 1997, the FERC put into effect rates to recover annual retail
electric transmission revenues of $301 million, effective March 31, 1998,
the operational date of the ISO and PX. The authorized revenues were
consistent with Utility electric transmission revenues in CPUC-authorized
1997 electric rates. In May 1998, the FERC allowed a $30 million increase
in retail electric transmission revenues, effective October 30, 1998. All
1998 retail electric transmission revenues are subject to refund pending
<PAGE>
rate review proceedings by the FERC. The Utility does not expect a material
change in transmission revenues resulting from the FERC's final decision.
The Utility Electric Distribution Business:
During the second quarter of 1998, the CPUC issued various decisions in
which it indicated its support for competition within the electric
distribution market. We believe that these regulatory pronouncements are
not consistent with prior CPUC policy on distribution competition, including
duplicative distribution facilities. Moreover, we believe that these
pronouncements have increased substantially the uncertainty surrounding the
future role of California's electric utility distribution companies. In
addition, we believe that the CPUC made these statements without a
comprehensive examination of such fundamental issues as: (1) recovery of
electric distribution transition costs; (2) the shifting of costs among
customer classes and geographic regions; (3) the economic and environmental
impacts of distribution competition; and (4) the distribution utilities'
statutory obligation to serve.
During the third quarter of 1998, the FERC issued a decision requiring
the Utility to provide wholesale transmission service to an irrigation
district. The district requested 16 points of interconnection with the
Utility's distribution facilities in order to serve 19 customers. The
Utility believes that the requested service is equivalent to retail
wheeling. The FERC decision may further facilitate duplicate electric
distribution facilities.
At this time, we cannot predict the extent that the CPUC or the FERC will
allow the future construction of duplicative distribution facilities by
other providers or the impact that future duplicative distribution
facilities and increased competition will have on the Utility's future
financial condition and results of operations.
The Utility Gas Business:
In March 1998, the Utility implemented a CPUC-approved accord with a broad
coalition of customer groups and industry participants that adopted market-
oriented policies in the Utility's natural gas transmission business. The
accord unbundled the Utility's gas transmission and storage services from
its distribution services and established gas transmission and storage rates
for the period March 1998 through December 2002. In addition, the accord
increases the opportunity for the Utility's residential and small commercial
(core) customers to purchase gas from competing suppliers.
In January 1998, the CPUC opened a rulemaking proceeding to further
expand market-oriented policies in California's gas industry. Policies
under consideration included the additional unbundling of services,
streamlining regulation for noncompetitive services, mitigating the
potential for anti-competitive behavior, and establishing appropriate
consumer protections. As required by the CPUC, several gas utilities,
including the Utility, and other interested parties filed reports with the
CPUC about gas market conditions. On August 6, 1998, the CPUC issued an
order requiring the utilities to file cost and rate undbundling applications
with the CPUC by February 26, 1999.
However, in August 1998, the California Legislature passed and the
Governor signed Senate Bill (SB) 1602, which requires the CPUC to submit to
the Legislature any findings or recommendations that would direct further
natural gas industry restructuring for core customers. SB 1602 also
prohibits the CPUC from enacting any such decision prior to January 1, 2000.
In light of this new law, the CPUC issued an order on October 8, 1998,
stating that it would not enforce its order from August 6, 1998. The CPUC
<PAGE>
plans to prepare a report for the Legislature identifying its proposed long
term market structure for the natural gas industry after hearings scheduled
to be held in January 1999. In concurrence with the new law, the CPUC will
not adopt a final market structure policy before January 1, 2000. At this
time, we cannot predict the outcome of these proceedings and their impact on
our financial position and results of operations.
Unregulated Business Operations:
We provide a wide range of integrated energy products and services designed
to take advantage of the competitive energy marketplace throughout the
United States. Through our unregulated subsidiaries, we: (1) provide gas
transmission services in Texas and the Pacific Northwest; (2) develop,
build, operate, own, and manage electric generation facilities across the
country; (3) provide customers nationwide with services to manage and make
more efficient their energy consumption; and (4) purchase and resell energy
commodities and related financial instruments. In providing integrated
energy products and services, we continually evaluate the composition of our
assets.
PG&E Corporation:
PG&E Corporation became the holding company of the Utility in 1997. At that
time, we transferred the unregulated subsidiaries of the Utility to PG&E
Corporation. A condition of the CPUC's approval of the holding company
formation was that the CPUC's Office of Ratepayer Advocates (ORA) oversee an
audit of transactions between the Utility and its affiliates for the period
1994 to 1996. The audit report, completed in November 1997, was critical of
the Utility's affiliate transaction internal controls and compliance. The
auditors recommended imposing conditions affecting the financing and
business composition of the Corporation.
In April 1998, the Utility filed testimony with the CPUC opposing the
recommended conditions. Hearings were completed in September 1998 to
determine if the additional recommended conditions should be imposed on PG&E
Corporation. We expect a final CPUC decision in early 1999.
If the CPUC imposed the recommended financial conditions on the
Corporation without modification, then such conditions could have an adverse
impact on future results of operations.
ACQUISITIONS AND SALES:
In July 1998, the Corporation sold its Australian energy holdings to Duke
Energy International, LLP (DEI), a subsidiary of Duke Energy Corporation.
The assets, located in the southeast corner of the Australian state of
Queensland, include a 627-kilometer gas pipeline, pipeline operations, and
trading and marketing operations.
The sale to DEI represents a premium on the price in local currency of
the Corporation's 1996 investment in the assets. However, the transaction
resulted in a non-recurring charge of $.06 per share in the second quarter,
primarily due to the 22 percent currency devaluation of the Australian
dollar against the U.S. dollar during the past two years.
On September 1, 1998, the Corporation, through its subsidiary U.S.
Generating Company (USGen), completed the acquisition of a portfolio of
electric generating assets and power supply contracts from the New England
Electric System (NEES) for $1.59 billion, plus $85 million for early
retirement and severance costs previously committed to by NEES. The
acquisition has been accounted for using the purchase method of accounting.
<PAGE>
Accordingly, the purchase price has been preliminarily allocated to the
assets purchased and the liabilities assumed based upon the fair values at
the date of acquisition.
Including fuel and other inventories and transaction costs, the
Corporation's financing requirements total approximately $1.8 billion,
funded through $1.3 billion of USGen debt and a $425 million equity
contribution. The net purchase price has been preliminarily allocated as
follows: (1) Property, plant, and equipment of $2.3 billion; (2) Receivable
for support payments of $0.8 billion; and (3) Contractual obligations of
$1.3 billion. The assets include hydroelectric, coal, oil, and natural gas
generation facilities with a combined generating capacity of 4,000 megawatts
(MW). In addition, USGen assumed 25 multi-year power purchase agreements
representing an additional 800 MW of production capacity. USGen entered
into agreements with NEES as part of the acquisition, which: (1) provide
that NEES shall make support payments over the next ten years to USGen for
the purchase power agreements; and (2) require that USGen provide
electricity to NEES under contracts that expire over the next four to twelve
years.
The Corporation acquired NEES's generating facilities and power supply
contracts in anticipation of deregulation of the electric industry in
several New England states. In Massachusetts, electric industry
restructuring legislation opened retail competition in the electric
generation business on March 1, 1998. However, a referendum requesting
voters to approve the continuation of this legislation in Massachusetts is
on the November 1998 ballot. If the voters vote to reject the legislation,
then the restructuring legislation in Massachusetts will be repealed. The
Corporation does not expect that a repeal of the Massachusetts legislation,
which relates primarily to the retail electricity market, would have a
material impact on its results of operations or financial position.
YEAR 2000:
The Year 2000 issue exists for the Corporation because many software and
embedded systems use only two digits to identify a year in a date field, and
were developed without considering the impact of the upcoming change in the
century. Some of these systems are critical to our operations and business
processes and might fail or function incorrectly if not repaired or replaced
with Year 2000 ready products. By "ready", we mean that the system is
remediated so that it will perform its essential functions. We define
"software" as both computer programming that has been developed by the
Corporation for its own purposes ("in-house software") and that purchased
from vendors ("vendor software"). "Embedded systems" refers to both
computing hardware and other electronic monitoring, communications, and
control systems that have microprocessors within them.
Our Year 2000 project focuses on those systems that are critical to our
business. By "critical" we mean those systems the failure of which would
directly and adversely affect our ability to generate or deliver our
products and services or otherwise affect revenues, safety, or reliability
for such a period of time as to lead to unrecoverable consequences. For
these critical systems, we have adopted a phased approach to address Year
2000 issues. The primary phases include: (1) an enterprise-wide inventory,
in which systems critical to our business are identified; (2) assessment, in
which critical systems are evaluated as to their readiness to operate after
December 31, 1999; (3) remediation, in which critical systems that are not
Year 2000 ready are made so, either through modifications or replacement;
(4) testing, in which remediation is validated by checking the ability of
the critical system to operate within the Year 2000 time frame; and
(5) certification, in which systems are formally acknowledged to be Year
2000 ready, and acceptable for production or operation.
<PAGE>
Our Year 2000 project is proceeding generally on schedule. For in-house
and vendor software, we have completed the inventory phase and have
identified approximately 1,000 critical systems. Additional software that
requires Year 2000 remediation may be discovered as we continue with the
assessment, remediation, and testing phases. We estimate that roughly 40
percent of identified, critical, in-house software has been remediated, with
completion of remediation of remaining in-house software scheduled for the
end of 1998. We estimate that roughly 10 percent of critical vendor
software has been remediated and received. Our corporate milestone for
receipt of all remediated vendor software is March 1999. We plan to finish
testing remediated in-house and vendor software by May 1999 and expect to
complete the certification phase for software by July 1999.
We also have completed the inventory of all embedded systems, although
additional embedded items that require Year 2000 repair or replacement may
be discovered as we continue with the assessment, remediation, and testing
phases. Remediation of all critical embedded systems is planned to be
completed by April 1999. We expect to finish testing of these remediated
systems by August 1999, and plan to complete the certification phase for
embedded systems by October 1999.
We are testing remediated software and embedded systems both for ability
to handle Year 2000 dates, including appropriate leap year calculations, and
to assure that code repair has not affected the base functionality of the
code. Software and embedded systems are tested individually and where
judged appropriate will be tested in an integrated manner with other
systems, with dates and data advanced and aged to simulate Year 2000
operations. Testing, by its nature, however, cannot comprehensively address
all future combinations of dates and events. Therefore, some uncertainty
will remain after testing is completed as to the ability of code to process
future dates, as well as the ability of remediated systems to work in an
integrated fashion with other systems.
We also depend upon external parties, including customers, suppliers,
business partners, gas and electric system operators, government agencies,
and financial institutions, to reliably deliver their products and services.
To the extent that any of these parties experience Year 2000 problems in
their systems, the demand for and the reliability of our services may be
adversely affected. The primary phases we have undertaken to deal with
external parties are: (1) inventory, in which critical business
relationships are identified; (2) action planning, in which we develop a
series of actions and a time frame for monitoring expected external party
compliance status; (3) assessment, in which the likelihood of external party
Year 2000 readiness is periodically evaluated; and (4) contingency planning,
in which appropriate plans are made to be ready to deal with the potential
failure of an external party to be Year 2000 ready.
We have completed our inventory of external contacts and have identified
more than 1,000 critical relationships. We soon will complete the action-
planning phase for each of these entities. Additional critical
relationships may be entered into or discovered as we continue. Assessment
of Year 2000 readiness of these external parties will continue through 1999.
We expect to complete contingency plans for each of these critical business
relationships by July 1999.
We plan to develop contingency plans for our critical software or
embedded systems for which we determine Year 2000 repair or replacement is
substantially at risk. For example, if the schedule for repairing or
replacing a non-compliant system lags and cannot be re-scheduled to meet
certain milestones, then we expect to begin an appropriate contingency
planning process. These contingency plans would be implemented as
necessary, if a remediated system does not become available by the date it
is needed. In addition, as described above, we plan to develop contingency
plans for the potential failure of critical external parties to fully
address their Year 2000 issues.
<PAGE>
We also recognize that, given the complex interaction of today's
computing and communication systems, we cannot be certain that all of our
efforts to have all critical systems Year 2000 ready will be successful.
Therefore, irrespective of the progress of the Year 2000 project, we are
preparing contingency plans for each subsidiary and essential business
function. These plans will take into account the possibility of multiple
system failures, both internal and external, due to Year 2000 effects.
These subsidiary and essential business function contingency plans will
build on existing emergency and business restoration plans. Although no
definitive list of scenarios for this planning has yet been developed, the
events that we considered for planning purposes include increased frequency
and duration of interruptions of the power, computing, financial, and
communications infrastructure. We expect to complete first drafts of these
subsidiary and essential business function contingency plans by the
beginning of 1999. We anticipate testing and revision of these plans
throughout 1999.
Due to the speculative nature of contingency planning, it is uncertain
whether our contingency plans to address failure of external parties or
internal systems will be sufficient to reduce the risk of material impacts
on our operations due to Year 2000 problems.
The Corporation currently is revising and refining its procedures for
tracking and reporting costs associated with its Year 2000 effort. From
1997 through September 1998, we have spent approximately $80 million to
assess and remediate Year 2000 problems. About $60 million of this cost was
for software systems that we replaced for business purposes generally
unrelated to addressing Year 2000 readiness, but whose schedule we advanced
to meet Year 2000 requirements. The replacement costs for these accelerated
systems were capitalized.
We estimate that our future costs to address Year 2000 issues will be
approximately $180 million. About $50 million of these remaining Year 2000
costs will be capitalized because they relate to the purchase and
installation of systems for general business purposes and the remaining $130
million will be expensed. As we continue to assess our systems and as the
remediation, testing, and certification phases of our compliance effort
progress, our estimated costs may change. Further, we expect to incur costs
in the year 2000 and beyond to remediate and replace less critical software
and embedded systems. We do not believe that the incremental cost of
addressing Year 2000 issues will have a material impact on the Corporation's
or the Utility's financial position or results of operation.
The Corporation's current schedule is subject to change, depending on
developments that may arise through further assessment of our systems, and
through the remediation and testing phases of our compliance effort.
Further, our current schedule is partially dependent on the efforts of third
parties, including vendors, suppliers, and customers. Delays by third
parties may cause our schedule to change. There also are risks associated
with loss of or inability to locate critical personnel to remediate and
return to service the identified critical systems. We may fail to locate
all systems critical to our business processes that require remediation. A
combination of businesses and government entities may fail to be Year 2000
ready, which may lead to a substantial reduction in a demand for our energy
services.
Based on our current schedule for the completion of Year 2000 tasks, we
believe our plan is adequate to secure Year 2000 readiness of our critical
systems. We expect our remediation efforts and those of external parties to
be largely successful. Nevertheless, achieving Year 2000 readiness is
subject to various risks and uncertainties, many of which are noted above.
We are not able to predict all the factors that could cause actual results
to differ materially from our current expectations as to our Year 2000
<PAGE>
readiness. If we, or third parties with whom we have significant business
relationships, fail to achieve Year 2000 readiness with respect to critical
systems, there could be a material adverse impact on the Utility's and the
Corporation's financial position, results of operations, and cash flows.
LIQUIDITY AND CAPITAL RESOURCES:
Sources of Capital:
- -------------------
The Corporation funds capital requirements from cash provided by operations
and, to the extent necessary, external financing. The Corporation's policy
is to finance its assets with a capital structure that minimizes financing
costs, maintains financial flexibility and, with regard to the Utility,
complies with regulatory guidelines. Based on cash provided from operations
and the Corporation's capital requirements, the Corporation may repurchase
equity and long-term debt in order to manage the overall balance of its
capital structure.
During the nine-month period ended September 30, 1998, the Corporation
issued $52 million of common stock, primarily through the Dividend
Reinvestment Plan and the Stock Option Plan. Also during the nine-month
period ended September 30, 1998, the Corporation paid dividends of $355
million and declared dividends of $343 million. The Utility paid dividends
of $315 million to PG&E Corporation during the nine-month period ended
September 30, 1998. In October 1998, the Utility declared dividends of $100
million payable to the Corporation in October. In October 1998, the
Corporation declared the fourth quarter regular common dividend of $.30 per
share payable January 15, 1999, to shareholders of record on December 15,
1998.
As of December 31, 1997, the Board of Directors had authorized the
repurchase of up to $1.7 billion of our common stock on the open market or
in negotiated transactions. As part of this authorization, in January 1998,
the Corporation repurchased in a specific transaction 37 million shares of
common stock. In connection with this transaction, the Corporation entered
into a forward contract with an investment institution. The Corporation
settled the forward contract in September 1998. There are no more
outstanding shares to be repurchased under this program.
The Corporation maintains a $500 million revolving credit facility,
which expires in 2002. In August 1997, we entered into an additional
$500 million 364-day credit facility, which expires on November 29, 1998.
The Corporation may extend the facilities annually for additional one-year
periods upon agreement with the banks. These credit facilities are used for
general corporate purposes and support our commercial paper program. The
Corporation had $469 million of commercial paper outstanding at September
30, 1998.
On September 1, 1998, USGen entered into a $1.675 billion revolving
credit facility. The facility is to be used for general corporate purposes.
The total amount outstanding at September 30, 1998, under the facility, was
$540 million in eurodollar loans and $788 million in short-term commercial
paper.
At September 30, 1998, GTT had $130 million of outstanding short-term
bank borrowings related to separate short-term credit facilities. The
borrowings are unrestricted as to use.
In July 1998, the Utility repurchased $800 million of its common stock
from PG&E Corporation, in addition to its $800 million common stock
repurchase from PG&E Corporation in April 1998.
The Utility's long-term debt matured, redeemed, or repurchased during the
nine-month period ended September 30, 1998, amounted to $962 million. Of
<PAGE>
this amount: (1) $249 million related to the Utility's redemption of its 8
percent mortgage bonds due October 1, 2025; (2) $252 million related to the
Utility's repurchase of its other mortgage bonds; and (3) $397 million
related to the maturity of the Utility's 5 3/8 percent mortgage bonds. The
remaining $64 million related primarily to the other scheduled maturity of
long-term debt. Also, PG&E Funding retired $193 million of the rate
reduction bonds during the nine-month period ended September 30, 1998.
In January 1998, the Utility redeemed its Series 7.44 percent preferred
stock with a face value of $65 million. In July 1998, the Utility redeemed
its Series 6-7/8 percent preferred stock with a face value of $43 million.
The Utility maintains a $1 billion revolving credit facility, which
expires in 2002. The Utility may extend the facility annually for
additional one-year periods upon agreement with the banks. There were no
borrowings under this credit facility at September 30, 1998.
Utility Cost of Capital:
- ------------------------
The CPUC authorized a return on rate base for the Utility's gas and electric
distribution assets for 1998 of 9.17 percent. The authorized 1998 cost of
common equity is 11.20 percent, which is lower than the 11.60 percent
authorized for 1997.
As discussed above, in Transition Cost Recovery, the CPUC separately
reduced the authorized return on common equity (ROE) on our Utility's
hydroelectric and geothermal generation assets to 90 percent of the
Utility's 1997 adopted cost of debt, or 6.77 percent. The Utility believes
that this reduction is inappropriate and has sought a rehearing of this
decision.
On May 8, 1998, the Utility filed its 1999 Cost of Capital Application
with the CPUC. The Utility requested a return on common equity of 12.1
percent and an overall return on rate base of 9.53 percent for its gas and
electric distribution operations. The Utility did not request a change in
its currently authorized capital structure of 46.2 percent debt, 5.8 percent
preferred equity, and 48 percent common equity.
On August 10, 1998, the CPUC's ORA filed its testimony recommending a ROE
of 8.64 percent for electric distribution operations and a ROE of 9.32
percent for gas distribution operations. ORA's recommended ROEs result in
recommended overall returns on rate base for electric and gas distribution
operations of 7.85 percent and 8.17 percent, respectively. If adopted by
the CPUC, then ORA's recommendation would result in decreases for 1999
electric and gas distribution revenues of $162 million and $38 million,
respectively, as compared to revenues based upon ROE currently authorized by
the CPUC.
The ORA's ROE recommendation for electric distribution operations is due
to its perception of the changing economic conditions in the past year, and
its perceived reduction in business risk for electric distribution
operations as compared to the formerly integrated generation, transmission,
and distribution operations. The ORA also believes that the CPUC's method
of adjusting the cost of capital annually based on incremental changes in
economic factors has led to what the ORA believes have been inflated
authorized returns in recent years.
To the extent the actual electric and gas rate bases adopted by the CPUC
in the GRC proceeding are less than the rate bases proposed by the Utility,
the estimated 1999 revenue reductions from the lower ROEs recommended by the
ORA in the cost of capital proceeding would be less. We expect the CPUC to
adopt a final decision in the cost of capital proceeding in February 1999,
and a final decision in the GRC proceeding in March 1999.
<PAGE>
1999 General Rate Case (GRC):
- -----------------------------
In December 1997, the Utility filed its 1999 GRC application with the CPUC.
During the GRC process, the CPUC examines the Utility's non-fuel related
costs to determine the amount it can charge customers. The Utility has
requested an increase in authorized revenues, to be effective January 1,
1999, of $572 million in electric base revenues and an increase of $460
million in gas base revenues over authorized 1998 revenues.
On June 26, 1998, the ORA provided their revenue requirement calculation,
which supplements ORA's June 8, 1998, report on the 1999 GRC proceeding.
The ORA recommended a decrease of $86 million in electric base revenues and
an increase in gas base revenues of $91 million over the Utility's 1998
authorized base revenues.
Hearings for the GRC before an administrative law judge took place from
August 24, 1998, through October 16, 1998. The administrative law judge
considers testimony and other evidence from many parties, including the ORA.
The Utility expects the CPUC to issue a proposed decision by the
administrative law judge in February 1999. The CPUC may accept all, part,
or none of the ORA's recommendations. We cannot predict the amount of base
revenue increase or decrease the CPUC ultimately will approve. In the event
of an adverse decision by the CPUC, and if the Utility is unable to lower
expenses to conform to the base revenue amounts adopted by the CPUC while
maintaining safety and system reliability standards, the ability of the
Utility to earn its authorized rate of return for the years 1999 through
2001 would be adversely affected.
The CPUC permitted the Utility to submit a plan for establishing interim
rates, effective January 1, 1999, to cover the period between that date and
the date the CPUC issues its decision. The CPUC plans to issue a decision
on interim rates in December 1998.
The 1999 GRC will not affect the authorized revenues for electric and gas
transmission services or for gas storage services. The Utility's authorized
revenues for each of these services are determined in other proceedings.
Environmental Matters:
- ----------------------
We are subject to laws and regulations established to both improve and
maintain the quality of the environment. Where our properties contain
hazardous substances, these laws and regulations require us to remove or
remedy the effect on the environment.
At September 30, 1998, the Utility expects to spend $282 million for
clean-up costs at identified sites over the next 30 years. If other
responsible parties fail to pay or expected outcomes change, then these
costs may be as much as $486 million. Of the $282 million, the Utility has
recovered $97 million and expects to recover $162 million in future rates.
Additionally, the Utility is seeking recovery of its costs from insurance
carriers and from other third parties. Further, as discussed above, the
Utility will retain the pre-closing remediation liability associated with
divested generation facilities. (See Note 4 of Notes to Consolidated
Financial Statements.)
Legal Matters:
- --------------
In the normal course of business, both the Utility and the Corporation are
named as parties in a number of claims and lawsuits. See Part II, Item 1,
Legal Proceedings and Note 4 to the Consolidated Financial Statements for
further discussion of significant pending legal matters.
<PAGE>
Risk Management Activities:
- ---------------------------
In the first quarter of 1998, the CPUC granted approval for the Utility to
use financial instruments to manage price volatility of gas purchased for
our Utility electric generation portfolio. The approval limits the
Utility's outstanding financial instruments to $200 million, with downward
adjustments occurring as the Utility divests its fossil-fueled generation
plants (see Utility Generation Divestiture, above). Authority to use these
risk management instruments ceases upon the full divestiture of fossil-
fueled generation plants or at the end of the current electric rate freeze
(see Rate Freeze and Rate Reduction, above), whichever comes first.
In the second quarter of 1998, the CPUC granted conditional authority to
the Utility to use natural gas-based financial instruments to manage the
impact of natural gas prices on the cost of electricity purchased pursuant
to existing power purchase contracts. Under the authority granted in the
CPUC decision, no natural gas-based financial instruments shall have an
expiration date later than December 31, 2001. Further, if the rate freeze
ends before December 31, 2001, the Utility shall net any outstanding
financial instrument contracts through equal and opposite contracts, within
a reasonable amount of time. Also during the second quarter, the Utility
filed an application with the CPUC to use natural gas-based financial
instruments to manage price and revenue risks associated with its natural
gas transmission and storage assets. See Note 1 for additional discussion
of risk management activities. The Utility currently does not use financial
instruments to manage price risk.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PG&E Corporation's and Pacific Gas and Electric Company's primary market
risk results from changes in energy prices and interest rates. We engage in
price risk management activities for both non-hedging and hedging purposes.
Additionally, we may engage in hedging activities using futures, options,
and swaps to hedge the impact of market fluctuations on energy commodity
prices, interest rates, and foreign currencies. (See Risk Management
Activities, above.)
<PAGE>
PART II. OTHER INFORMATION
---------------------------
Item 1. Legal Proceedings
-----------------
A. Texas Franchise Fee Litigation
As previously disclosed in PG&E Corporation and Pacific Gas and Electric
Company's Annual Report on Form 10-K for the fiscal year ended December 31,
1997, and in a Current Report on Form 8-K dated August 25, 1998, in
connection with PG&E Corporation's acquisition of Valero Energy Corporation
(Valero), now known as PG&E Gas Transmission, Texas Corporation (GTT),
various PG&E Corporation entities (formerly Valero entities) are defendants
in eight lawsuits pending in several Texas state courts involving claims
related to, among other things, the payment of franchise fees or street use
fees to Texas cities and municipalities and the conduct of the defendants.
On June 15, 1998, a jury trial began in the 92nd State District Court,
Hidalgo County, Texas, in the case of the City of Edinburg (City) v. Rio
Grande Valley Gas Co. (RGVG), Valero Energy Corporation (now known as GTT),
Valero Transmission Company (now known as PG&E Texas Pipeline Company),
Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company),
Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings
Corporation), Valero Transmission, L.P. (now known as PG&E Texas Pipeline,
L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy,
L.P.), and Southern Union Gas Company and certain affiliates (SU). At
issue, among other things, in the case is the franchise agreement entered
into between RGVG, the local gas distribution company, and the City on
October 1, 1985, to permit RGVG to sell gas and construct, maintain, own,
and operate gas pipelines in city streets. At the time of entering into the
franchise agreement, RGVG was a wholly owned subsidiary of Valero. Valero
(now GTT) sold RGVG to Southern Union Gas Company on September 30, 1993.
On August 14, 1998, a jury returned a verdict in favor of the City and
awarded damages in the approximate aggregate amount of $9.8 million, plus
attorneys' fees of approximately $3.5 million, against GTT, SU and various
affiliates. The jury found that RGVG committed fraud in connection with
entering into the franchise agreement and further found that RGVG failed to
comply with the franchise agreement with respect to payments due under the
agreement. The jury also found that RGVG transferred the rights,
privileges, and duties required to be performed by RGVG under the agreement
without the express written consent of the City. The jury found that GTT
and various GTT subsidiaries tortiously interfered with the franchise
agreement and that the City did not consent to the location of GTT's
pipelines on public easements within the City. Also, the jury found that
GTT was responsible for the conduct of RGVG from October 1, 1985 (the date
the franchise agreement was entered into) until September 30, 1993 (the date
GTT, then known as Valero, sold RGVG to Southern Union).
The jury refused to award punitive damages against the GTT defendants. A
hearing on the plaintiff's motion for entry of judgment has been scheduled
for December 1, 1998, after which the court will enter a judgment. At the
hearing, the court may provide guidance as to how the damages and attorneys'
fees of approximately $13.3 million will be apportioned among the parties.
If an adverse judgment is entered, GTT and its various subsidiaries intend
to appeal the judgment.
The Corporation believes the ultimate outcome of the Texas franchise fees
cases described above will not have a material adverse impact on its
financial position or results of operation.
<PAGE>
Item 5. Other Information
-----------------
A. Ratio of Earnings to Fixed Charges and Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
Pacific Gas and Electric Company's earnings to fixed charges ratio for the
nine months ended September 30, 1998 was 3.01. Pacific Gas and Electric
Company's earnings to combined fixed charges and preferred stock dividends
ratio for the nine months ended September 30, 1998 was 2.84. The statement
of the foregoing ratios, together with the statements of the computation of
the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included
herein for the purpose of incorporating such information and exhibits into
Registration Statement Nos. 33-62488, 33-64136, 33-50707 and 33-61959,
relating to Pacific Gas and Electric Company's various classes of debt and
first preferred stock outstanding.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 10.1 PG&E Corporation Deferred Compensation Plan for
Officers, as amended and restated July 22, 1998
Exhibit 10.2 PG&E Corporation Deferred Compensation Plan for
Directors, as amended and restated July 22, 1998
Exhibit 10.3 PG&E Corporation Executive Stock Ownership Program,
as amended and restated July 22, 1998
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
Exhibit 27.1 Financial Data Schedule for the quarter ended
September 30, 1998 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
September 30, 1998 for Pacific Gas and Electric
Company
(b) Reports on Form 8-K during the third quarter of 1998 and
through the date hereof (1):
1. July 10, 1998
Item 5. Other Events
A. Electric Industry Restructuring
1. California Voter Initiative
2. Divestiture
B. Pacific Gas and Electric Company's General Rate Case
Proceeding
C. Sale of Australian Assets
2. July 16, 1998
Item 5. Other Events
A. Second Quarter 1998 Consolidated Earnings(unaudited)
3. August 25, 1998
<PAGE>
Item 5. Other Events
A. Pacific Gas and Electric Company's 1999 Cost of Capital Proceeding
B. Texas Franchise Fee Litigation
4. October 21, 1998
Item 5. Other Events
A. Third Quarter 1998 Consolidated Earnings
(unaudited)
(1) Unless otherwise noted, all Reports on Form 8-K were filed under
both Commission File Number 1-12609 (PG&E Corporation) and Commission
File Number 1-2348(Pacific Gas and Electric Company)
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrants have duly caused this report to be signed on their
behalf by the undersigned thereunto duly authorized.
PG&E CORPORATION
and
PACIFIC GAS AND ELECTRIC COMPANY
CHRISTOPHER P. JOHNS
November 2, 1998 By
-----------------------
CHRISTOPHER P. JOHNS
Vice President and Controller
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company
<PAGE>
Exhibit Index
Exhibit No. Description of Exhibit
10.1 PG&E Corporation Deferred Compensation Plan for Officers,
as amended and restated July 22, 1998
10.2 PG&E Corporation Deferred Compensation Plan for
Directors, as amended and restated July 22, 1998
10.3 PG&E Corporation Executive Stock Ownership Program, as
amended and restated July 22, 1998
11 Computation of Earnings Per Common Share
12.1 Computation of Ratio of Earnings to Fixed Charges for
Pacific Gas and Electric Company
12.2 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas and
Electric Company
27.1 Financial Data Schedule for the quarter ended September
30, 1998 for PG&E Corporation
27.2 Financial Data Schedule for the quarter ended September
30, 1998 for Pacific Gas and Electric Company
<PAGE>
EXHIBIT 10.1
PG&E CORPORATION
DEFERRED COMPENSATION PLAN
FOR OFFICERS
1. Purpose
-------
This is the controlling and definitive statement of the PG&E
Corporation Deferred Compensation Plan for Officers
("PLAN").1/ The PLAN which became effective on November 5,
1997, takes the place of and assumes the existing benefits
accrued under the Deferred Compensation Plan of the Pacific
Gas and Electric Company. The PLAN provides an opportunity
for OFFICERS and other designated key employees of the
CORPORATION and its subsidiaries and affiliates to defer
payment of (1) part of their salaries, (2) all or part of
their INCENTIVE PLAN AWARDS, (3) all of their SAVINGS FUND
PLAN EXCESS BENEFITS, (4) PERQUISITE ALLOWANCES under the
Executive Flexible Perquisites Program, (5) all or a portion
of their PERFORMANCE UNITS under the Performance Unit Plan,
and (6) such other payments, awards, allowances, or benefits
as the COMMITTEE may in the future determine appropriate.
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS are automatically
credited to participant accounts maintained by the PLAN.
2. Definitions
-----------
(a) "BENEFICIARY" means the person, persons, or entity
designated by the PLAN participant on the DEFERRAL ELECTION
FORM to receive payment of the participant's DEFERRED
COMPENSATION ACCOUNT in the event of the death of the
participant.
(b) "BOARD" and "BOARD OF DIRECTORS" means the BOARD OF
DIRECTORS of the CORPORATION or, when appropriate, any
committee of the BOARD which has been delegated authority to
take action with respect to the PLAN.
(c) "COMMITTEE" means the Nominating and Compensation
Committee of the BOARD.
(d) "CORPORATION" means PG&E Corporation, a California
corporation.
(e) "DEFERRAL ELECTION FORM" means a participation form to
be supplied by the Human Resources Department of the
CORPORATION.
(f) "DEFERRED COMPENSATION ACCOUNT" means the bookkeeping
account established pursuant to Section 6 on behalf of each
ELIGIBLE EMPLOYEE who elects to participate in the PLAN.
(g) "ELIGIBLE EMPLOYEE" means an OFFICER and such other key
employees as may be designated by the PLAN ADMINISTRATOR as
eligible to participate in the PLAN.
_______________________________
1/ Words in all capitals are defined in Section 2.
<PAGE>
(h) "INCENTIVE PLAN AWARD" means a monetary award payable
under the annual short-term performance incentive plan
maintained by the CORPORATION, or any of its subsidiaries or
affiliates.
(i) "OFFICER" means all OFFICERS of the CORPORATION and its
subsidiaries and affiliates in Officer Band 6 and above.
(j) "PERFORMANCE UNITS" means the amounts which are payable
as a result of units earned under the CORPORATION'S
Performance Unit Plan, as may be revised thereafter from
time to time.
(k) "PERQUISITE ALLOWANCE" means the amounts which an
OFFICER can use for the reimbursement of certain designated
expenses under the CORPORATION'S Executive Flexible
Perquisites Program.
(l) "PLAN" means the PG&E Corporation Deferred Compensation
Plan for Officers.
(m) "PLAN ADMINISTRATOR" shall mean the senior Human
Resources officer of the CORPORATION.
(n) "SALARY" means the amount of compensation payable by
the CORPORATION or by any of its subsidiaries or affiliates
to an ELIGIBLE EMPLOYEE for his or her duties. It does not
include any amount payable with respect to services rendered
prior to an ELIGIBLE EMPLOYEE'S election to defer according
to Section 5 of this PLAN.
(o) "SAVINGS FUND PLAN EXCESS BENEFITS" means amounts
payable to OFFICERS under the SAVINGS FUND PLAN EXCESS
BENEFITS arrangement as originally adopted on December 20,
1989, and as may be revised thereafter from time to time.
(p) "SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS" means the
special premiums awarded to eligible OFFICERS under the
Executive Stock Ownership Guidelines approved by the
COMMITTEE on October 15, 1997, as amended on July 22, 1998,
and as may hereafter be amended from time to time.
(q) "TERMINATION DATE" means the last day on which the PLAN
participant is an employee of the CORPORATION, one of its
subsidiaries, or of an association affiliated with the
CORPORATION.
(r) "YEAR" means the calendar YEAR.
3. Eligibility
-----------
Each OFFICER who receives a SALARY for service as an OFFICER
of the CORPORATION shall be eligible to participate in the
PLAN. Any other ELIGIBLE EMPLOYEE shall be eligible to
participate in the PLAN consistent with the terms set by the
PLAN ADMINISTRATOR in its designation of such key employee
as an ELIGIBLE EMPLOYEE.
<PAGE>
4. Participation
-------------
In order to commence participation in the PLAN, a
participant must file a DEFERRAL ELECTION FORM with the PLAN
ADMINISTRATOR. An election to defer (i) an INCENTIVE PLAN
AWARD, (ii) PERFORMANCE UNITS or (iii) SALARY must be filed
prior to the beginning of the YEAR in which said amounts are
paid. An election to defer SAVINGS FUND PLAN EXCESS
BENEFITS must be filed prior to the beginning of the Savings
Fund Plan YEAR to which the Excess Benefits are
attributable. An election to defer PERQUISITE ALLOWANCES
must be filed prior to the beginning of the YEAR in which
said amounts are granted. SPECIAL INCENTIVE STOCK OWNERSHIP
PREMIUMS are automatically deferred into the PLAN
immediately upon grant. Notwithstanding the foregoing, upon
first becoming an ELIGIBLE EMPLOYEE, an election to
participate shall be effective for the month following the
filing of a DEFERRAL ELECTION FORM, provided said Form is
filed within 60 days following the date when the employee
first becomes an ELIGIBLE EMPLOYEE.
(a) Deferral of SALARY
------------------
A participant may defer from 5 percent to
30 percent of his or her monthly SALARY.
(b) Deferral of INCENTIVE PLAN AWARDS
---------------------------------
A participant may defer all or part of his or her
INCENTIVE PLAN AWARDS.
(c) Deferral of SAVINGS FUND PLAN EXCESS BENEFITS
---------------------------------------------
A participant may defer all amounts which would
otherwise be paid in cash under the SAVINGS FUND
PLAN EXCESS BENEFITS arrangement. Partial
deferrals of SAVINGS FUND PLAN EXCESS BENEFITS are
not permitted.
(d) Deferral of PERQUISITE ALLOWANCES
---------------------------------
A participant may elect to defer any portion of
his or her flexible PERQUISITE ALLOWANCE.
(e) Deferral of PERFORMANCE UNITS
-----------------------------
A participant may elect to defer all or part of
his or her PERFORMANCE UNITS.
(f) Deferral of SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS
------------------------------------------------------
All of an OFFICER'S SPECIAL INCENTIVE STOCK
OWNERSHIP PREMIUMS are automatically deferred to
the PLAN immediately upon grant and converted into
units representing shares of PG&E Corporation
common stock. The units attributable to SPECIAL
INCENTIVE STOCK OWNERSHIP PREMIUMS and any
additional units resulting from the conversion of
dividend equivalents thereon remain unvested until
the earlier of the third anniversary of the date
on which the SPECIAL INCENTIVE STOCK OWNERSHIP
PREMIUMS are credited to an OFFICER'S DEFERRED
COMPENSATION ACCOUNT, death,
<PAGE>
disability, or
retirement of the participant. (The term
"disability" shall, for purposes of the PLAN, have
the same meaning as in Section 22(e)(3) of the
Internal Revenue Code.) Unvested units
attributable to SPECIAL INCENTIVE STOCK OWNERSHIP
PREMIUMS and any additional units resulting from
the conversion of dividend equivalents thereon
shall be forfeited if an OFFICER'S stock ownership
falls below the levels set forth in the Executive
Stock Ownership Guidelines.
Upon the conversion of SPECIAL INCENTIVE STOCK
OWNERSHIP PREMIUMS to units in accordance with
Section 6, and the credit of additional units upon
the conversion of dividend equivalents thereon, an
equal number of shares of PG&E Corporation common
stock shall be reserved from the pool of shares
authorized for issuance under the PG&E Corporation
Long-Term Incentive Program. Upon forfeiture of
such units, a number of shares equal to the number
of forfeited units shall again become available
for issuance under the PG&E Corporation Long-Term
Incentive Program.
5. Deferral Election
-----------------
An ELIGIBLE EMPLOYEE who elects to participate in the PLAN
shall file an executed DEFERRAL ELECTION FORM with the PLAN
ADMINISTRATOR which (i) indicates the percentage of SALARY
and applicable pay periods, and the amount of any INCENTIVE
PLAN AWARD, PERFORMANCE UNITS, SAVINGS FUND PLAN EXCESS
BENEFITS, PERQUISITE ALLOWANCES, and such other eligible
payments, awards, allowances, or benefits to be deferred
under the PLAN; and (ii) specifies the time and form of
distribution and designates a BENEFICIARY. A participant
may not elect to defer the receipt of SALARY, any INCENTIVE
PLAN AWARD, PERFORMANCE UNITS, or SAVINGS FUND PLAN EXCESS
BENEFITS, for less than three years, subject to earlier
distribution following termination of employment in
accordance with Section 9.
The participant's deferral election of SALARY shall continue
from YEAR to YEAR until terminated or modified by written
notice to the PLAN ADMINISTRATOR. Notice of termination of
SALARY deferrals shall not become effective until the first
day of the month following the month in which such written
notice is received by the PLAN ADMINISTRATOR. A participant
who terminates SALARY deferrals shall not be permitted to
elect future SALARY deferrals earlier than the first day of
the following YEAR. A participant may modify a prior
deferral election of SALARY only by delivering a new
DEFERRAL ELECTION FORM to the PLAN ADMINISTRATOR to be
effective as of the first day of the following YEAR. In no
event shall any termination or modification of deferrals
affect amounts deferred prior to the effective date of such
termination or modification.
Deferral elections of INCENTIVE PLAN AWARDS, PERFORMANCE
UNITS, SAVINGS FUND PLAN EXCESS BENEFITS, and PERQUISITE
ALLOWANCES, only are effective for the YEAR following the
YEAR in which the executed DEFERRAL ELECTION FORM is filed
with the PLAN ADMINISTRATOR. Thereafter, a new DEFERRAL
ELECTION FORM must be filed with the PLAN ADMINISTRATOR in
order to maintain deferrals in subsequent years. All
deferral elections of INCENTIVE PLAN AWARDS, PERFORMANCE
UNITS, SAVINGS FUND PLAN EXCESS BENEFITS, and PERQUISITE
ALLOWANCES may be revoked prior to the beginning of the YEAR
in which INCENTIVE PLAN AWARDS, PERFORMANCE UNITS, and
<PAGE>
PERQUISITE ALLOWANCES would otherwise be paid, and
thereafter shall be irrevocable. All deferral elections of
SAVINGS FUND PLAN EXCESS BENEFITS may be revoked prior to
the beginning of the Savings Fund Plan YEAR to which the
Excess Benefits are attributable.
Notwithstanding the foregoing, the participant's designation
as to time and form of distribution to the participant may
not be revoked or modified by the participant as to amounts
already deferred, except as permitted by the PLAN
ADMINISTRATOR pursuant to Section 10 in the case of hardship
withdrawals.
6. Credits to DEFERRED COMPENSATION ACCOUNT
----------------------------------------
Upon receipt of a completed DEFERRAL ELECTION FORM, the
CORPORATION shall establish a DEFERRED COMPENSATION ACCOUNT
to which shall be credited such amounts as the participant
has elected to defer under the terms of the PLAN.
SALARY which is deferred shall be credited to the
participant's DEFERRED COMPENSATION ACCOUNT as of each
payroll period. SAVINGS FUND PLAN EXCESS BENEFITS which are
deferred shall be credited to the participant's DEFERRED
COMPENSATION ACCOUNT as of the first business day following
the end of the YEAR to which such Excess Benefits are
attributable. PERQUISITE ALLOWANCES which are deferred
shall be credited to the participant's DEFERRED COMPENSATION
ACCOUNT on the date of grant. PERFORMANCE UNITS and
INCENTIVE PLAN AWARDS which are deferred shall be credited
to the participant's DEFERRED COMPENSATION ACCOUNT as of the
date such amounts would otherwise have been paid.
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS shall be credited
to the participant's DEFERRED COMPENSATION ACCOUNT
immediately upon the date of grant and converted into units
(including fractions computed to three decimal places)
representing shares of PG&E Corporation common stock. The
initial value of a SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM
unit shall be the average of the daily high and low price of
a share of PG&E Corporation common stock as traded on the
New York Stock Exchange for the 30 trading days preceding
the date that the SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM
is credited to a participant's DEFERRED COMPENSATION
ACCOUNT. Thereafter, the value of a SPECIAL INCENTIVE STOCK
OWNERSHIP PREMIUM unit shall fluctuate with the closing
price of a share of PG&E Corporation common stock. Whenever
dividends are declared with respect to the Corporation's
common stock, additional SPECIAL INCENTIVE STOCK OWNERSHIP
PREMIUM units (including fractions computed to three decimal
places) shall be credited to a participant's account on the
dividend payment date in an amount determined by dividing
(i) the aggregate amount of dividends, i.e., the dividend
multiplied by the number of SPECIAL INCENTIVE STOCK
OWNERSHIP PREMIUM units credited to the participant's
account as of the dividend record date, by (ii) the closing
price of PG&E Corporation common stock on the New York Stock
Exchange on the dividend payment date.
7. Earnings During Deferral Period
-------------------------------
At such time as participant elects to participate in the
PLAN, he shall also elect to have his account balances
allocated to the Utility Bond Fund or to the PG&E
Corporation Phantom Stock Fund. Participant shall make such
elections and in such percentages as
<PAGE>
the PLAN ADMINISTRATOR
shall prescribe. Participant shall be able to reallocate
account balances between the funds and reallocate new
deferrals at such time and in such manner as the PLAN
ADMINISTRATOR shall prescribe; provided, however, that units
attributable to SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUMS
and additional units resulting from the conversion of
dividend equivalents thereon may not be reallocated.
Anything to the contrary herein notwithstanding, a
participant may not reallocate account balances between
funds if such reallocation would result in a non-exempt
Discretionary Transaction as defined in Rule 16b-3 of the
Securities Exchange Act of 1934, as amended, or any
successor to Rule 16b-3, as in effect when the reallocation
is requested.
(a) Utility Bond Fund
-----------------
On the first business day of each calendar quarter,
interest shall be credited on the balance in each
participant's DEFERRED COMPENSATION ACCOUNT as of the
last day of the immediately preceding calendar quarter
and prorated based on the number of days in the quarter
that the balance was allocated to the Utility Bond
Fund. Such interest shall be at a rate equal to the AA
Utility Bond Yield reported in Moody's Public Utility,
published in the issue of Moody's Investors Service
immediately preceding the first day of the calendar
quarter in which the interest is to be credited. Such
interest shall become a part of the DEFERRED
COMPENSATION ACCOUNT and shall be paid at the same time
or times as the balance of the DEFERRED COMPENSATION
ACCOUNT. Notwithstanding the above, if a participant
has requested that his account balance be reallocated
to the PG&E Corporation Phantom Stock Fund before the
end of the quarter, prorated interest on the
participant's account balance shall be calculated at a
rate equal to the AA Utility Bond Yield reported in
Moody's Public Utility, published in the issue of
Moody's Investors Service immediately preceding the
date of reallocation, shall be credited to the
participant's account on the date of reallocation, and
shall be subject to the reallocation request.
(b) PG&E Corporation Phantom Stock Fund
-----------------------------------
Deferrals credited to the PG&E Corporation Phantom
Stock Fund shall be converted into units (including
fractions computed to three decimal places) each
representing share of PG&E Corporation common stock.
The value of a unit for purposes of determining the
number of units to credit upon initial deferral or
reallocation from the Utility Bond Fund, and for
determining the dollar value of the aggregate number of
units to be reallocated from the PG&E Corporation
Phantom Stock Fund to the Utility Bond Fund, shall be
the average of the daily high and low price of a share
of PG&E Corporation common stock as traded on the New
York Stock Exchange for the 30 trading days preceding
(i) the date that deferrals and reallocations are
credited to a participant's account in the PG&E
Corporation Phantom Stock Fund in the case of new
deferrals and reallocations from the Utility Bond Fund,
and (ii) the date the PLAN ADMINISTRATOR receives a
reallocation request, in the case of reallocations.
Thereafter, the value of a unit shall fluctuate in
accordance with the closing price of PG&E Corporation
common stock on the New York Stock Exchange.
Whenever dividends are paid with respect to the
Corporation's common stock, additional units (including
fractions computed to three decimal places) shall be
credited to a participant's account on the dividend
payment date in an amount determined by dividing (i)
the aggregate amount of dividends, i.e,. the dividend
multiplied by the number of units credited to the
participant's account as of the
<PAGE>
dividend record date,
by (ii) the closing price of PG&E Corporation common
stock on the New York Stock Exchange on the dividend
payment date. If, after the record date but before the
dividend payment date, a participant's balance in the
PG&E Corporation Phantom Stock Fund has been
reallocated to the Utility Bond Fund, or has been paid
to the participant or the participant's beneficiary,
then an amount equal to the aggregate dividend shall be
credited to the participant's account in the Utility
Bond Fund, or paid directly to the participant or the
participant's beneficiary, whichever is applicable.
8. Effect of Deferral on Qualified Benefit PLANS
---------------------------------------------
A participant who participates in this PLAN shall continue
to be eligible to participate in all CORPORATION benefit
PLANS. However, no amount deferred under this PLAN shall be
deemed to be covered compensation or SALARY for the purposes
of computing percentage of participation and benefits to
which the OFFICER may be entitled under the CORPORATION
Retirement and Savings Fund Plans and any other CORPORATION
benefit plans which are qualified under Section 401(a) of
the Internal Revenue Code of 1986, as amended.
9. Form and Time of Payment to a Participant of DEFERRED
-----------------------------------------------------
COMPENSATION ACCOUNT
--------------------
Payment to the participant of deferred compensation
allocated to the Utility Bond Fund or the PG&E Corporation
Phantom Stock Fund shall be made in the form of cash. At
the election of the participant, the cash may be paid in a
lump sum or in a series of ten or less approximately equal
annual installments. Payment to the participant shall be
made at such time and in such form as the participant has
specified on the DEFERRAL ELECTION FORM(s) previously filed
with the PLAN ADMINISTRATOR; provided however, that payments
shall commence (either as a lump sum or as the first of a
series of ten or less approximately equal annual
installments) no later than January of the YEAR following
the YEAR in which the participant's employment terminated.
Payment to a participant of his or her DEFERRED COMPENSATION
ACCOUNT shall be made in January of each YEAR in which
payment is to be made in accordance with the participant's
DEFERAL ELECTION FORM. All payments from the DEFERRED
COMPENSATION ACCOUNT shall be subject to all tax
withholdings or other reductions which may be required by
law.
For purposes of this Section 9 and Sections 10 and 11 below,
the amount of cash to be distributed upon settlement of
units credited to a participant's account in the PG&E
Corporation Phantom Stock Fund shall be equal to the number
of credited units, or fraction thereof, multiplied by the
average of the high and low price of a share of PG&E
Corporation common stock as traded on the New York Stock
Exchange for the 30 trading days preceding the date of
distribution.
Notwithstanding the foregoing, following a participant's
termination of employment, deferrals attributable to SPECIAL
INCENTIVE STOCK OWNERSHIP PREMIUMS shall only be distributed
in January of the YEAR following termination in the form of
one or more certificates for a number of shares of PG&E
Corporation common stock equal to the number of vested
SPECIAL INCENTIVE STOCK OWNERSHIP PREMIUM units, rounded
down to the nearest whole share.
<PAGE>
10. Distribution Due to Unforeseeable Emergency
-------------------------------------------
A participant may request a distribution due to an
Unforeseeable Emergency by submitting a written request to
the Plan Administrator accompanied by evidence to
demonstrate that the circumstances being experienced qualify
as an Unforeseeable Emergency. The Plan Administrator shall
have the authority to require such evidence as it deems
necessary to determine if a distribution is warranted. If
an application for a hardship distribution due to an
Unforeseeable Emergency is approved, the distribution is
limited to the amount sufficient to meet the emergency. The
allowed distribution shall be payable in a method determined
by the Plan Administrator as soon as possible after approval
of such distribution. A participant who has commenced
receiving installment payments under the Plan may request
acceleration of such payments in the event of an
Unforeseeable Emergency. The Administrator may permit
accelerated payments to the extent such accelerated payment
does not exceed the amount necessary to meet the emergency.
For purposes of this Section 10, an "Unforeseeable Emergency
" means a severe financial hardship to the participant
resulting from a sudden and unexpected illness or accident
of the participant or of a dependent of the participant,
loss of the participant's property due to casualty, or other
similar extraordinary and unforeseeable circumstances
arising as a result of events beyond the control of the
participant. The circumstances that will constitute an
"Unforeseeable Emergency" would depend upon the facts in
each case, but, in any case, payment may not be made in the
event that such hardship is or may be relieved (i) through
prompt reimbursement or compensation by insurance or
otherwise, (ii) by liquidation of the participant's assets,
to the extent that liquidation of such assets would not
itself cause severe financial hardship, or (iii) by
cessation of deferrals under the Plan. The need to send a
participant's child to college or the desire to purchase a
home shall not be an Unforeseeable Emergency.
11. Effect of Death of Participant
------------------------------
Upon the death of a participant who participated in the
PLAN, all amounts, if any, remaining in his or her DEFERRED
COMPENSATION ACCOUNT shall be distributed to the BENEFICIARY
designated by the participant. Payment to the beneficiary
shall be made at such time and in such form as the
participant has previously specified in a form previously
filed with the PLAN ADMINISTRATOR; provided however, that
payments shall commence (either as a lump sum or as the
first of a series of ten or less approximately equal annual
installments) no later than January of the YEAR following
the YEAR in which the participant's death occurred.
Earnings, as determined under Section 7 of the PLAN, shall
be credited to the date of distribution. Any shares of PG&E
Corporation common stock to be issued in settlement of the
deceased participant's SPECIAL INCENTIVE STOCK OWNERSHIP
PREMIUM units shall be issued in the name of the
participant's designated beneficiary. If the designated
BENEFICIARY does not survive the participant or dies before
receiving payment in full of the participant's DEFERRED
COMPENSATION ACCOUNT, a lump sum payment of the remaining
balance (and a distribution of the shares of PG&E
Corporation common stock issuable in settlement of the
deceased participant's SPECIAL INCENTIVE STOCK OWNERSHIP
PREMIUM units) shall be made as soon as practicable to the
estate of whoever dies last, the participant or the
designated BENEFICIARY. All BENEFICIARY designations may be
changed by the participant at any time without the consent
of a BENEFICIARY. The participant shall notify the PLAN
ADMINISTRATOR in writing of any such change of BENEFICIARY.
<PAGE>
12. Participant's Rights Unsecured
------------------------------
The interest under the PLAN of any participant and such
participant's right to receive a distribution of his or her
DEFERRED COMPENSATION ACCOUNT shall be an unsecured claim
against the general assets of the CORPORATION. The DEFERRED
COMPENSATION ACCOUNT shall consist of bookkeeping entries
only, and this PLAN does not create an interest in, nor
permit a claim against, any specific asset of the
CORPORATION pursuant to the PLAN.
13. Annual Statement of DEFERRED COMPENSATION ACCOUNT
-------------------------------------------------
As soon as practicable after the close of each YEAR, each
participant shall be provided with a statement describing
the status of his or her DEFERRED COMPENSATION ACCOUNT as of
the end of the preceding YEAR. The statement shall reflect
the totals of amounts deferred during the YEAR, the amount
of interest credited, the amount of PG&E Corporation Phantom
Stock Fund units, the amount of SPECIAL INCENTIVE STOCK
OWNERSHIP PREMIUMS (if any), the amount of payments made
during the YEAR, if any, and the net balance remaining in
the account at the end of the YEAR.
14. Nonassignability of Interests
-----------------------------
The interest and property rights of any participant under
the PLAN shall not be assignable either by voluntary or
involuntary assignment or by operation of law, including
(without limitation) bankruptcy, garnishment, attachment or
other creditor's process, and any act in violation of this
Section 14 shall be void.
15. Administration of the PLAN
--------------------------
The PLAN shall be administered by the PLAN ADMINISTRATOR.
The PLAN ADMINISTRATOR shall have full power and authority
to administer and interpret the PLAN, to establish
procedures for administering the PLAN, and to take any and
all necessary action in connection therewith. The PLAN
ADMINISTRATOR's interpretation and construction of the PLAN
shall be conclusive and binding on all persons.
16. Amendment or Termination of the PLAN
------------------------------------
The CORPORATION may amend, suspend, or terminate the PLAN at
any time. In the event of such termination, the DEFERRED
COMPENSATION ACCOUNTS of participants shall be paid in
accordance with the participant's deferral election.
<PAGE>
EXHIBIT 10.2
PG&E CORPORATION
DEFERRED COMPENSATION PLAN
FOR NON-EMPLOYEE DIRECTORS
(As Amended and Restated Effective as of July 22, 1998)
1. Establishment and Purpose
-------------------------
The is the controlling and definitive statement of the PG&E
Corporation Deferred Compensation Plan for Non-Employee
Directors ("Plan"). The Plan was originally adopted on
December 18, 1996, by the Board of Directors of PG&E
Corporation to provide Directors of PG&E Corporation an
opportunity to defer payment of their Meeting Fees and
Retainer Fees. The Plan is also intended to establish a
method of paying Meeting Fees and Retainer Fees which will
assist the Corporation in attracting and retaining persons
of outstanding achievement and ability as members of the
Board of Directors of the Corporation.
2. Definitions
-----------
(a) "Beneficiary" means the person, persons, or entity
designated by the Director to receive payment of the Director's
Deferred Compensation Account in the event of the death of the
Director.
(b) "Board" and "Board of Directors" means the Board of
Directors of the Corporation.
(c) "Committee" shall mean the Nominating and Compensation
Committee of the Board.
(d) "Corporation" means PG&E Corporation, a California
corporation.
(e) "Deferred Compensation Account" means the bookkeeping
account established pursuant to Section 6 on behalf of each
Director who elects to participate in the Plan.
(f) "Deferred Election Form" means a participation form to be
supplied by the Secretary of the Corporation.
(g) "Director" means a member of the Board of Directors who is
not an employee of the Corporation or any subsidiary thereof.
(h) "Director's Termination Date" shall mean the effective date
of the Director's resignation from the Board of Directors of the
Corporation.
(i) "Meeting Fee" means the amount of compensation paid by the
Corporation to a Director for his or her attendance and services
at a meeting of the Board of Directors or any committee thereof.
A Meeting Fee shall not include (i) any Retainer Fee, (ii) any
reimbursement by the Corporation of expenses incurred by a
Director incidental to attendance at a meeting of the Board of
Directors or of a committee thereof or of any other expense
incurred on behalf of the Corporation, or (iii) any amount
payable with respect to services rendered prior to January 1,
1997.
<PAGE>
(j) "Plan" shall mean the PG&E Corporation Deferred Compensation
Plan for Non-Employee Directors.
(k) "Retainer Fee" means the amount of compensation paid by the
Corporation to a Director for retaining his or her services
during a calendar quarter. A Retainer Fee shall not include (i)
any Meeting Fee, (ii) any reimbursement by the Corporation of
expenses incurred by a Director incidental to attendance at a
meeting of the Board of Directors or of a committee thereof or of
any other expense incurred on behalf of the Corporation, or (iii)
any amount payable with respect to services rendered prior to
January 1, 1997.
(l) "Year" shall mean the calendar year.
3. Eligibility
-----------
Each Director who receives a Meeting Fee or Retainer Fee for
service on the Board of Directors shall be eligible to
participate in the Plan.
4. Participation
-------------
In order to commence participation in the Plan in 1997, a
Director must file a deferral election with the Secretary of
the Corporation prior to January 1, 1997. In order to
commence participation in the Plan for calendar quarters
commencing on or after April 1, 1997, a Director must file a
Deferral Election Form with the Secretary of the Corporation
prior to the first day of the calendar quarter for which
participation is to become effective. Notwithstanding the
foregoing, in the case of a newly elected Director, an
election to participate shall be effective for the calendar
quarter in which the Director is first elected if it is
filed before the date the Director first receives a Meeting
Fee or Retainer Fee (but in no event later than one month
following the date of election).
A participating Director may defer:
(a) All Retainer Fees only; or
(b) All Meeting Fees only; or
(c) All Retainer Fees and all Meeting Fees.
The Retainer Fees and Meeting Fees deferred under (a), (b),
or (c), above, shall be net of any amounts which a Director
has authorized the Corporate Secretary to transmit to the
Corporation's Dividend Reinvestment Plan. Partial deferral
of Retainer Fees or Meeting Fees is not permitted.
Payment to the Director of deferred compensation may, at the
election of the participating Director, be paid in a lump
sum or in a series of ten or less approximately equal annual
installments. Payment to the Director shall commence in the
Year following the Director's Termination Date or in such
earlier Year as the Director may specify on the Deferral
Election Form; provided however, that a Director may not
elect to defer the receipt of Retainer Fees or Meeting Fees
for less than three years.
<PAGE>
5. Deferral Election
-----------------
A Director who elects to participate in the Plan shall file
an executed Deferral Election Form with the Secretary of the
Corporation indicating the compensation to be deferred, the
time and form of distribution, and the Beneficiary
designations described in Section 9.
The Director's deferral election shall become effective and
apply with respect to Meeting Fees and Retainer Fees earned
for the first calendar quarter after the Deferral Election
Form is filed with the Secretary of the Corporation and all
subsequent calendar quarters until revoked (by electing not
to further defer either Meeting Fees or Retainer Fees) or
modified by the Director. The Director shall notify the
Secretary of the Corporation in writing of any such
revocation or modification, which shall apply solely to
amounts deferred with respect to calendar quarters following
the calendar quarter in which the revocation or modification
is received by the Secretary of the Corporation.
Notwithstanding the foregoing, the Director's designation as
to time and form of distribution to the Director of deferred
compensation may not be revoked or modified by the Director
either as to amounts already deferred or as to amounts to be
deferred in the future.
6. Credits to Deferred Compensation Account
----------------------------------------
Upon receipt of a duly filed Deferral Election Form, the
Corporation shall establish a Deferred Compensation Account
to which shall be credited an amount equal to the Meeting
Fees and/or Retainer Fees which would have been payable
currently to the Director but for the terms of the deferral
election.
Retainer Fees and Meeting Fees shall be credited to the
Director's Deferred Compensation Account as of the following
dates:
(a) The deferred Retainer Fee for each calendar quarter shall be
credited to such Account as of the first business day of such
calendar quarter; and
(b) The deferred Meeting Fee shall be credited to such Account
as of the date of the meeting for which the Meeting Fee was
earned.
7. Earnings During Deferral Period
-------------------------------
At such time as participant elects to participate in the
Plan, he shall also elect to have his account balances
credited to the Utility Bond Fund or to the PG&E Corporation
Phantom Stock Fund. Participant shall make such elections
and in such percentages as the Secretary of the Corporation
shall prescribe. Participant shall be able to reallocate
account balances between the funds and reallocate new
deferrals at such time and in such manner as the Secretary
of the Corporation shall prescribe; provided, however, that
a participant may not reallocate PG&E Corporation Phantom
Stock Fund units and the earnings thereon which were
credited to a participant's Deferred Compensation Account in
connection with the termination of the PG&E Corporation
Retirement Plan for Non-Employee Directors. Anything to the
contrary herein notwithstanding, a participant may not
reallocate account balances between funds if such
reallocation would result in a non-
<PAGE>
exempt discretionary transaction under Rule 16b-3 of the
Securities Exchange Act of 1934, as amended, or any successor
to Rule 16b-3, as in effect when the reallocation is requested.
(a) Utility Bond Fund
-----------------
On the first business day of each calendar quarter,
interest shall be credited on the balance in each
participant's Deferred Compensation Account as of the
last day of the immediately preceding calendar quarter.
Such interest shall be at a rate equal to the AA
Utility Bond Yield reported in Moody's Public Utility,
published in the issue of Moody's Investors Service
immediately preceding the first day of the calendar
quarter in which the interest is to be credited. Such
interest shall become a part of the Deferred
Compensation Account and shall be paid at the same time
or times as the balance of the Deferred Compensation
Account. Notwithstanding the above, if a participant
has requested that his account balance be reallocated
to the PG&E Corporation Phantom Stock Fund before the
end of the quarter, prorated interest on the
participant's account balance shall be calculated at a
rate equal to the AA Utility Bond Yield reported in
Moody's Public Utility, published in the issue of
Moody's Investors Service immediately preceding the
date of reallocation, shall be credited to the
participant's account on the date of reallocation, and
shall be subject to the reallocation request.
(b) PG&E Corporation Phantom Stock Fund
-----------------------------------
Deferrals credited to this Fund shall be converted into
units (including fractions computed to three decimal
places) each representing a share of PG&E Corporation
stock. The value of a unit for purposes of determining
the number of units to credit upon initial deferral or
reallocation from the Utility Bond Fund, and for
determining the dollar value of the aggregate number of
units to be reallocated from the PG&E Corporation
Phantom Stock Fund to the Utility Bond Fund, shall be
the average of the daily high and low price of a share
of PG&E Corporation common stock as traded on the New
York Stock Exchange for the 30 trading days preceding
(i) the date that deferrals and reallocations are
credited to a participant's account in the PG&E
Corporation Phantom Stock Fund in the case of new
deferrals and reallocations from the Utility Bond Fund,
and (ii) the date the Secretary of the Corporation
receives a reallocation request, in the case of
reallocations. Thereafter, the value of a unit shall
fluctuate in accordance with the closing price of PG&E
Corporation common stock on the New York Stock
Exchange.
Whenever dividends are paid with respect to the
Corporation's common stock, additional units (including
fractions computed to three decimal places) shall be
credited to a participant's account on the dividend
payment date in an amount determined by dividing (i)
the aggregate amount of dividends, i.e,. the dividend
multiplied by the number of units credited to the
participant's account as of the dividend record date,
by (ii) the closing price of PG&E Corporation common
stock on the New York Stock Exchange on the dividend
payment date. If, after the record date but before the
dividend payment date, a participant's balance in the
PG&E Corporation Phantom Stock Fund has been
reallocated to the Utility Bond Fund, or has been paid
to the participant or the participant's beneficiary,
then an amount equal to the aggregate dividend shall be
credited to the participant's
<PAGE>
account in the Utility Bond Fund, or paid directly to the
participant or the participant's beneficiary, whichever
is applicable.
8. Form and Time of Payment to a Director of Deferred
--------------------------------------------------
Compensation Account
--------------------
Payment to a Director of his or her Deferred Compensation
Account shall be made in cash. At the election of the
participant, the cash may be paid in a lump sum or in a
series of ten or less approximately equal annual
installments. Payment to the participant shall be made at
such time and in such form as the participant has specified
on the Director's deferral election form; provided, however,
that payments shall commence (either as a lump sum or as the
first of a series of ten or less approximately equal annual
installments) no later than January of the Year following
the Year in which the participant's service on the Board
terminated. Payment to a participant of his or her deferred
compensation account shall be made in January of each Year
in which payment is to be made in accordance with the
participant's deferral election.
Notwithstanding the foregoing, amounts attributable to PG&E
Corporation Phantom Stock Fund units and the earnings
thereon which were credited to a participant's Deferred
Compensation Account in connection with the termination of
the PG&E Corporation Retirement Plan for Non-Employee
Directors may not be distributed from the Plan until after
the participant retires from the Board or age 65, whichever
event occurs later. Such amounts shall be paid in a lump
sum or in a series of ten or less approximately equal
installments as previously specified by the Director.
Payment shall commence in January of the Year following the
Year in which the Director retired or attained age 65,
whichever is later.
For purposes of this Section 8 and Section 9 below, the
amount of cash to be distributed upon settlement of units
credited to a participant's account in the PG&E Corporation
Phantom Stock Fund shall be equal to the number of credited
units, or fraction thereof, multiplied by the average of the
high and low price of a share of PG&E Corporation common
stock as traded on the New York Stock Exchange for the 30
trading days preceding the date of distribution.
9. Effect of Death of Participant
------------------------------
Upon the death of a Director who participated in the Plan,
all amounts, if any, remaining in his or her Deferred
Compensation Account shall be distributed to the Beneficiary
designated by the Director. Payment to the Beneficiary
shall be made at such time and in such form as the
participant has previously specified in a form previously
filed with the Secretary of the Corporation; provided
however, that payments shall commence (either as a lump sum
or as the first of a series of ten or less approximately
equal annual installments) no later than January of the Year
following the Year in which the participant's death
occurred. The Committee, however, reserves the right to
determine in its sole discretion that payment shall be made
at a different time or times (but no later than ten years
after the death of the Director). Earnings, as determined
under Section 7 of the Plan, shall be credited to the date
of distribution.
If the designated Beneficiary does not survive the Director
or dies before receiving payment in full of the Director's
Deferred Compensation Account, payment of the remaining
balance shall be made as soon as practicable in a lump sum
to the estate of the last to die of the Director or the
designated Beneficiary. All Beneficiary designations
<PAGE>
including selection of the timing and manner of payments to
any Beneficiary) may be revoked or modified at the
Director's option without the consent of the Beneficiary.
The Director shall notify the Secretary of the Corporation
in writing of any such revocation or modification.
10. Participant's Rights Unsecured
------------------------------
The interest under the Plan of any participating Director
and such Director's right to receive a distribution of his
or her Deferred Compensation Account shall be an unsecured
claim against the general assets of the Corporation. The
Deferred Compensation Account shall consist of bookkeeping
entries only, and no Director shall have an interest in or
claim against any specific asset of the Corporation pursuant
to the Plan.
11. Statement of Deferred Compensation Account
------------------------------------------
The Secretary of the Corporation shall provide to each
participating Director an annual statement of his or her
Deferred Compensation Account no later than January 31 each
year.
12. Nonassignability of Interests
-----------------------------
The interests and property rights of any Director under the
Plan shall not be assignable either by voluntary or
involuntary assignment or by operation of law, including
(without limitation) bankruptcy, garnishment, attachment or
other creditor's process, and any act in violation of this
Section 12 shall be void.
13. Administration of the Plan
--------------------------
The Plan shall be administered by the Committee. In
addition to the powers and duties otherwise set forth in the
Plan, the Committee shall have full power and authority to
administer and interpret the Plan, to establish procedures
for administering the Plan, and to take any and all neces
sary action in connection therewith. The Committee's
interpretation and construction of the Plan shall be
conclusive and binding on all persons.
14. Amendment or Termination of the Plan
------------------------------------
The Board of Directors may amend, suspend, or terminate the
Plan at any time. In the event of such termination, the
Deferred Compensation Accounts of participating Directors
shall be paid at such times and in such forms as shall be
determined pursuant to Section 8, unless the Board of
Directors shall prescribe a different time or times for
payments of such Accounts.
<PAGE>
EXHIBIT 10.3
PG&E CORPORATION
EXECUTIVE STOCK OWNERSHIP PROGRAM
Administrative Guidelines
-------------------------
(As amended July 22, 1998)
1. Description. The Executive Stock Ownership Program
("Program") was approved by the Nominating and Compensation
Committee of the Board of Directors on October 15, 1997. The
Program is an important element of the Committee's compensation
policy of aligning executive interests with those of the
Corporation's shareholders. As an integral part of the Program,
the Committee also authorized the use of Special Incentive Stock
Ownership Premiums ("SISOPs") which are designed to provide
incentives to Eligible Executives to assist in achieving minimum
stock ownership targets established by the Committee. These
Guidelines were originally adopted by the Committee on November
19, 1997, and were amended by the Committee on July 22, 1998.
These amended Guidelines, along with the written materials
provided to the Committee on October 15, 1997, describe the
Program which became effective on January 1, 1998. The Program
is administered by the Corporation's Senior Human Resources
Officer.
2. Eligible Executives. The Chief Executive Officer shall
designate the officers of the Corporation and its affiliates who
shall be Eligible Executives covered by the Program. Initially,
the officers covered by the Guidelines and the applicable stock
ownership Target are:
Officer Band Position Stock Ownership Target
1 CEO 3 x base salary
2 Heads of Business 2 x base salary
Lines, CFO, &
General Counsel
3 SVPs of Corp. 1.5 x base salary
3. Annual Milestones. Under the Guidelines, stock ownership
levels are designed to be achieved by the end of the fifth
calendar year following the calendar year in which an officer
first becomes an Eligible Executive ("Target Date"). Annual
Milestones have been established as a means of measuring progress
towards achieving Targets and of providing incentives for
Eligible Executives to expeditiously meet their Targets. The
Annual Milestone at the end of the first full calendar year is 20
percent of the Target, and the Annual Milestone for each
succeeding year is an additional 20 percent of the Target.
Annual Milestones shall be adjusted to reflect changes in base
salary; provided, however, that in each instance any such
modification shall be amortized over the remaining original five-
year term. Following the Target Date, annual Targets also shall
be modified to reflect changes in base salary.
<PAGE>
4. Calculation of Stock Ownership Levels. Stock ownership
level is the dollar value of stock and stock equivalents owned by
an Eligible Executive and calculated as of the last day of the
calendar year ("Measurement Date"). The purpose of this
calculation is to determine the value of the stock or stock
equivalents owned by the Eligible Executive as compared with the
Annual Milestone or Target for that executive. For purposes of
this calculation, the value per share of stock or stock
equivalent ("Measurement Value") is the average closing price of
PG&E Corporation common stock as traded on the New York Stock
Exchange for the last thirty (30) trading days of the year.
a) The value of stock beneficially owned by the Eligible
Executive is determined by multiplying the number of shares owned
beneficially on the Measurement Date times the Measurement Value.
b) The value of PG&E Corporation phantom stock units credited
to the Eligible Executive's account in the PG&E Corporation
Deferred Compensation Plan for Officers ("DCP") is determined by
multiplying the number of phantom stock units credited to the
Eligible Executive's DCP account on the Measurement Date times
the Measurement Value.
c) The value of stock held in the PG&E Corporation stock fund
of any defined contribution plan maintained by PG&E Corporation
or any of its subsidiaries is the value of the Eligible
Executive's PG&E Corporation stock fund on the Measurement Date.
d) The value of vested stock options is the difference between
the number of options multiplied by the Measurement Value minus
the number of options multiplied by the option exercise price
(for purposes of this calculation, any value attributable to
dividend equivalents is excluded).
5. Award of SISOPs. SISOPs are awarded to Eligible Executives
who achieve and maintain stock ownership levels prior to the end
of the third year following the year in which an officer first
became an Eligible Executive. For purposes of determining
awards, the total stock ownership level is calculated as set
forth under paragraph 4, on the Measurement Date. The amount of
a SISOP award shall be equal to:
a) For the first year, 20 percent of the amount of the Eligible
Executive's stock ownership level at the end of the year, up to
the Annual Milestone, plus an additional 30 percent of the amount
by which the stock ownership level exceeds the Annual Milestone
up to the target; and
b) For each of the second and third years, 20 percent of the
amount up to the Annual Milestone by which the end of the year
stock ownership level exceeds the beginning of the year stock
ownership level, plus an additional 30 percent of the amount by
which the end of the year balance exceeds the Annual Milestone,
up to the Target.
Each time a SISOP award calculation is made, a second
calculation also is made to determine the minimum number of
shares which must be retained by the Eligible Executive to
avoid forfeiture of the SISOP award ("Minimum Ownership
Level") as discussed below in paragraph 8. This calculation
converts the dollar value of the stock ownership level used
as the basis for qualifying for SISOPs into a number of
shares of
<PAGE>
stock. It is calculated by dividing the stock
ownership level by the Measurement Value. Thus, for
example, if an Eligible Executive's stock ownership level
was $250,000 and the Measurement Value was $25 per share,
then the Minimum Ownership Level would be 10,000 shares.
For purposes of this calculation, the maximum share
ownership level used is the Eligible Executive's Target. If
an Eligible Executive has a share ownership level higher
than his/her Target, the increment over the Target is not
included. Thus, for example, if an Eligible Executive has a
Target of $750,000 and his/her share ownership level is
$900,000, then only $750,000 is used to calculate the
Minimum Ownership Level.
6. Vesting. SISOPs vest only upon the expiration of three
years after the date of award, or, if earlier, upon an Eligible
Executive's death, disability, or retirement.
7. SISOPs Credited to the Deferred Compensation Plan. Upon
award, SISOPs are credited to the Eligible Executive's DCP
account and converted into units of phantom stock each equal in
value to a share of PG&E Corporation common stock ("SISOP units")
as determined in accordance with paragraph 6 of the DCP. Once a
SISOP unit is credited to the Eligible Executive's DCP account,
it shall be subject to all of the terms and conditions
specifically applicable to SISOP units under the DCP. Once
vested, SISOP units are distributed in the form of an equal
number of shares of PG&E Corporation common stock as provided in
the DCP. The SISOP units constitute "incentive awards"
authorized to be awarded by the Committee to Eligible Executives
under the PG&E Corporation Long-Term Incentive Program ("LTIP").
Upon credit of SISOP units to an Eligible Executive's DCP
account, an equal number of shares of PG&E Corporation common
stock shall be reserved for issuance from the pool of shares
authorized for issuance under the LTIP.
8. Forfeiture of SISOP Units. So long as SISOP units remain
unvested, such units are subject to forfeiture if, on each
Measurement Date, the Eligible Executive's stock ownership is
less than the Minimum Ownership Level established when the SISOPs
were granted (see paragraph 5). To determine forfeiture, the
following steps are followed on each Measurement Date:
a) The number of shares and PG&E Corporation phantom stock
units credited to the Eligible Executive's DCP account is
determined.
b) The share-equivalent of the value of the vested "in the
money" stock options is determined by dividing the value of such
options (computed in the manner described in 4(d)) by the current
Measurement Value (e.g., if the value of the vested "in the
money" options is $100,000 and the current Measurement Value is
$25 per share, then the share equivalent is 4,000 shares).
c) The number of shares, PG&E Corporation phantom stock units,
and share-equivalents of vested "in the money" options is added
together. This total ("Current Holdings") is compared with the
Minimum Ownership Level determined when the SISOPs were granted.
If the Current Holdings are equal to or greater than the Minimum
Ownership Level, then no unvested SISOP units are forfeited. If
the Current Holdings are less than the Minimum Ownership Level,
then the unvested SISOP units are forfeited in
<PAGE>
the same proportion as the Current Holdings are less than Minimum
Ownership Level (for example, if the Current Holdings are 20
percent less than the Minimum Ownership Level, then 20 percent of
the SISOP units are forfeited).
9. Failure to Achieve or Maintain Target. Failure to achieve
stock ownership levels at Target on the Target Date, or to
maintain stock ownership levels at Target on any Measurement Date
thereafter, will result in the deferral into the PG&E Corporation
Phantom Stock Fund of the DCP of annual awards from the
Performance Unit Plan ("PUP") and the Short Term Incentive Plan
("STIP"). As of any Measurement Date, to the extent that stock
ownership levels are below Target, PUP awards shall be converted
into PG&E Corporation Phantom Stock Units and held in the PG&E
Corporation Phantom Stock Fund of the DCP. If, with the addition
of the phantom stock units attributable to the PUP award, the
stock ownership level is still below Target for any Measurement
Date, any STIP award above target STIP also shall be converted
into phantom stock units, to the extent necessary to achieve the
Target stock ownership level. Such conversion of PUP and STIP
awards shall continue for successive Measurement Dates, if
necessary, until Target is met. Phantom stock units attributable
to PUP and STIP awards described in this paragraph 9 will be paid
from the DCP in a lump sum in January of the year following the
year in which the Eligible Executive's employment terminates, or
upon such earlier date as may have been elected by the Eligible
Executive within thirty days after the date of mandatory deferral
of PUP and/or STIP awards which date shall not be earlier than
three (3) years after the date of mandatory deferral.
<PAGE>
<TABLE>
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
<CAPTION>
- ----------------------------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
-------------------- ------------------------
(in millions, except per share amounts) 1998 1997 1998 1997
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
EARNINGS PER COMMON SHARE (EPS) AS SHOWN
IN THE STATEMENT OF CONSOLIDATED INCOME
Earnings available for common stock $ 210 $ 257 $ 523 $ 622
========== ========== ========== ==========
Average common shares outstanding 382 414 382 407
========== ========== ========== ==========
Basic EPS $ 0.55 $ 0.62 $ 1.37 $ 1.53
========== ========== ========== ==========
DILUTED EPS (1)
Earnings available for common stock $ 210 $ 257 $ 523 $ 622
========== ========== ========== ==========
Average common shares outstanding 382 414 382 407
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) 1 - 1 -
---------- ---------- ---------- ----------
Average common shares outstanding as
adjusted 383 414 383 407
========== ========== ========== ==========
Diluted EPS $ 0.55 $ 0.62 $ 1.37 $ 1.53
========== ========== ========== ==========
- ----------------------------------------------------------------------------------------------
<FN>
(1) This presentation is submitted in accordance with Statement of Financial Accounting
Standards No. 128.
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
ended -------------------------------------------------------
(dollars in millions) September 30, 1998 1997 1996 1995 1994 1993
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 554 $ 768 $ 755 $ 1,339 $ 1,007 $1,065
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 - - 3 4 (3) 7
Income tax expense 480 609 555 895 837 902
Net fixed charges 515 628 683 716 729 775
-------- -------- -------- -------- -------- --------
Total Earnings $ 1,549 $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 446 $ 485 $ 574 $ 616 $ 639 $ 652
Interest on short-
term borrowings 40 101 75 83 77 88
Interest on capital leases 1 2 3 3 2 2
Capitalized Interest - 1 1 - 2 46
AFUDC Debt 10 16 7 11 11 33
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 18 24 24 3 - -
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 515 $ 629 $ 684 $ 716 $ 731 $ 821
======== ======== ======== ======== ======== ========
Ratios of Earnings to
Fixed Charges 3.01 3.19 2.92 4.13 3.52 3.35
- ----------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing Pacific Gas and Electric 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, cash distributions from and equity in
undistributed income or loss of Pacific Gas and Electric Company's 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 of subordinated debentures held by trust, interest on capital leases, and
earnings required to cover the preferred stock dividend requirements.
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Nine months Year ended December 31,
ended -------------------------------------------------------
(dollars in millions) September 30, 1998 1997 1996 1995 1994 1993
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 554 $ 768 $ 755 $ 1,339 $ 1,007 $ 1,065
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 - - 3 4 (3) 7
Income tax expense 480 609 555 895 837 902
Net fixed charges 515 628 683 716 729 775
-------- -------- -------- -------- -------- --------
Total Earnings $ 1,549 $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 446 $ 485 $ 574 $ 616 $ 639 $ 652
Interest on short-
term borrowings 40 101 75 83 77 88
Interest on capital leases 1 2 3 3 2 2
Capitalized Interest - 1 1 - 2 46
AFUDC Debt 10 16 7 11 11 33
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 18 24 24 3 - -
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 515 $ 629 $ 684 $ 716 $ 731 $ 821
-------- -------- -------- -------- -------- --------
Preferred Stock Dividends:
Tax deductible dividends $ 7 $ 10 $ 10 $ 11 $ 5 $ 5
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 24 39 39 100 96 109
-------- -------- -------- -------- -------- --------
Total Preferred
Stock Dividends $ 31 $ 49 $ 49 $ 111 $ 101 $ 114
-------- -------- -------- -------- -------- --------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 546 $ 678 $ 733 $ 827 $ 832 $ 935
======== ======== ======== ======== ======== ========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.84 2.96 2.72 3.57 3.09 2.94
- ---------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing Pacific Gas and Electric 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, cash
distributions from and equity in undistributed income or loss of Pacific
Gas and Electric Company's 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, interest of subordinated
debentures held by trust, and earnings required to cover the preferred stock dividend
requirements of majority owned subsidiaries. "Preferred stock dividends" represent pretax
earnings which would be required to cover such dividend requirements.
</TABLE>
<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from PG&E
Corporation and is qualified in its entirety by reference to such financial
statements.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 18,206
<OTHER-PROPERTY-AND-INVEST> 644
<TOTAL-CURRENT-ASSETS> 3,838
<TOTAL-DEFERRED-CHARGES> 2,744
<OTHER-ASSETS> 6,206
<TOTAL-ASSETS> 31,638
<COMMON> 5,848
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2,111
<TOTAL-COMMON-STOCKHOLDERS-EQ> 7,959
437
343
<LONG-TERM-DEBT-NET> 6,476
<SHORT-TERM-NOTES> 1,937
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 584
<LONG-TERM-DEBT-CURRENT-PORT> 358
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 13,544
<TOT-CAPITALIZATION-AND-LIAB> 31,638
<GROSS-OPERATING-REVENUE> 14,447
<INCOME-TAX-EXPENSE> 464
<OTHER-OPERATING-EXPENSES> 12,880
<TOTAL-OPERATING-EXPENSES> 12,880
<OPERATING-INCOME-LOSS> 1,567
<OTHER-INCOME-NET> 24
<INCOME-BEFORE-INTEREST-EXPEN> 1,591
<TOTAL-INTEREST-EXPENSE> 604
<NET-INCOME> 523
0
<EARNINGS-AVAILABLE-FOR-COMM> 523
<COMMON-STOCK-DIVIDENDS> 352
<TOTAL-INTEREST-ON-BONDS> 260
<CASH-FLOW-OPERATIONS> 2,515
<EPS-PRIMARY> 1.37
<EPS-DILUTED> 1.37
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from Pacific Gas
and Electric Company and is qualified in its entirety by reference to such
financial statements.
</LEGEND>
<SUBSIDIARY>
<NUMBER> 1
<NAME> PACIFIC GAS AND ELECTRIC COMPANY
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 12,858
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 2,175
<TOTAL-DEFERRED-CHARGES> 2,618
<OTHER-ASSETS> 4,817
<TOTAL-ASSETS> 22,468
<COMMON> 3,806
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2,186
<TOTAL-COMMON-STOCKHOLDERS-EQ> 5,992
437
287
<LONG-TERM-DEBT-NET> 5,559
<SHORT-TERM-NOTES> 10
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 10
<LONG-TERM-DEBT-CURRENT-PORT> 275
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 9,898
<TOT-CAPITALIZATION-AND-LIAB> 22,468
<GROSS-OPERATING-REVENUE> 6,706
<INCOME-TAX-EXPENSE> 480
<OTHER-OPERATING-EXPENSES> 5,257
<TOTAL-OPERATING-EXPENSES> 5,257
<OPERATING-INCOME-LOSS> 1,449
<OTHER-INCOME-NET> 78
<INCOME-BEFORE-INTEREST-EXPEN> 1,527
<TOTAL-INTEREST-EXPENSE> 493
<NET-INCOME> 554
21
<EARNINGS-AVAILABLE-FOR-COMM> 533
<COMMON-STOCK-DIVIDENDS> 200
<TOTAL-INTEREST-ON-BONDS> 260
<CASH-FLOW-OPERATIONS> 2,755
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0.00
</TABLE>
