FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
----------------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 August 6, 1998:
PG&E Corporation 381,991,996 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 JUNE 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.............19
RESULTS OF OPERATIONS.....................................21
Common Stock Dividend..................................22
Earnings Per Common Share..............................22
Utility Results........................................22
Unregulated Business Results...........................23
FINANCIAL CONDITION.......................................23
COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........23
THE UTILITY ELECTRIC GENERATION BUSINESS..................23
Competitive Market Framework...........................23
Electric Transition Plan...............................24
Rate Freeze and Rate Reduction.........................25
Transition Cost Recovery...............................25
Utility Generation Divestiture.........................27
Utility Generation Impairment..........................28
Customer Impacts of Transition Plan....................28
California Voter Initiative............................29
THE UTILITY ELECTRIC TRANSMISSION BUSINESS................30
THE UTILITY ELECTRIC DISTRIBUTION BUSINESS................31
THE UTILITY GAS BUSINESS..................................31
UNREGULATED BUSINESS OPERATIONS...........................32
PG&E CORPORATION..........................................32
ACQUISITIONS AND SALES....................................32
YEAR 2000.................................................33
LIQUIDITY AND CAPITAL RESOURCES
Sources of Capital.....................................34
Utility Cost of Capital................................35
1999 General Rate Case.................................36
Environmental Matters..................................36
Legal Matters..........................................37
Risk Management Activities.............................37
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................37
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.........................................38
ITEM 5. OTHER INFORMATION.........................................39
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................39
SIGNATURE..........................................................41
<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 June 30, Six months ended June 30,
1998 1997 1998 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating Revenues
Utility $ 2,117 $ 2,279 $ 4,143 $ 4,553
Energy commodities and services 2,670 804 4,997 1,896
-------- -------- -------- --------
Total operating revenues 4,787 3,083 9,140 6,449
-------- -------- -------- --------
Operating Expenses
Cost of energy for utility 569 659 1,235 1,383
Cost of energy commodities and services 2,468 735 4,620 1,753
Operating and maintenance, net 609 852 1,116 1,553
Depreciation and decommissioning 581 466 1,143 925
-------- -------- -------- --------
Total operating expenses 4,227 2,712 8,114 5,614
-------- -------- -------- --------
Operating Income 560 371 1,026 835
Interest expense, net 202 164 405 322
Other income and (expense) (5) 75 14 92
-------- -------- -------- --------
Income Before Income Taxes 353 282 635 605
Income taxes 179 89 322 240
-------- -------- -------- --------
Net Income $ 174 $ 193 $ 313 $ 365
======== ======== ======== ========
Weighted Average Common Shares
Outstanding 382 398 382 403
Earnings Per Common Share, Basic and Diluted $ .46 $ .49 $ .82 $ .91
Dividends Declared Per Common Share $ .30 $ .30 $ .60 $ .60
<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 June 30, December 31,
1998 1997
------------ -----------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 311 $ 237
Short-term investments 39 1,160
Accounts receivable
Customers, net 1,437 1,514
Regulatory balancing accounts 590 658
Energy marketing 807 830
Inventories and prepayments 638 626
-------- --------
Total current assets 3,822 5,025
Property, Plant, and Equipment
Utility 24,736 24,185
Gas transmission 3,484 3,484
Other 263 57
-------- --------
Total property, plant, and equipment (at original cost) 28,483 27,726
Accumulated depreciation and decommissioning (12,196) (11,617)
-------- --------
Net property, plant, and equipment 16,287 16,109
Other Noncurrent Assets
Regulatory assets 6,335 6,700
Nuclear decommissioning funds 1,098 1,024
Other 1,747 1,699
-------- --------
Total noncurrent assets 9,180 9,423
-------- --------
TOTAL ASSETS $ 29,289 $ 30,557
======== ========
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 576 $ 103
Current portion of long-term debt 508 659
Current portion of rate reduction bonds 289 125
Accounts payable
Trade creditors 622 754
Other 434 466
Energy marketing 734 758
Accrued taxes 390 226
Other 722 893
-------- --------
Total current liabilities 4,275 3,984
Noncurrent Liabilities
Long-term debt 7,503 7,659
Rate reduction bonds 2,511 2,776
Deferred income taxes 4,028 4,029
Deferred tax credits 317 339
Other 1,958 1,978
-------- --------
Total noncurrent liabilities 16,317 16,781
Preferred Stock of Subsidiary With Mandatory Redemption Provisions 193 193
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 184 257
Common stock 5,834 6,366
Reinvested earnings 2,041 2,531
-------- --------
Total stockholders' equity 8,204 9,299
Commitments and Contingencies (Notes 2 and 4) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 29,289 $ 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 six months ended June 30, 1998 1997
---------- ----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 313 $ 365
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning, and amortization 1,199 985
Deferred income taxes and tax credits-net (31) (106)
Other deferred charges and noncurrent liabilities (607) 8
Gain on sale of assets - (110)
Loss on sale of assets 21 -
Net effect of changes in operating assets
and liabilities:
Accounts receivable 100 92
Regulatory balancing accounts receivable 365 (41)
Inventories 42 (3)
Accounts payable (187) (128)
Accrued taxes 165 115
Other working capital (135) (175)
Other-net 5 141
--------- ---------
Net cash provided by operating activities 1,250 1,143
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (925) (770)
Investments in unregulated projects (22) (97)
Acquisitions - (41)
Proceeds from sale of assets - 137
Other-net 36 (32)
--------- ---------
Net cash used by investing activities (911) (803)
--------- ---------
Cash Flows From Financing Activities
Common stock issued 33 27
Common stock repurchased (1,123) (575)
Long-term debt issued 199 50
Long-term debt matured, redeemed, or repurchased-net (644) (344)
Short-term debt issued (redeemed)-net 473 848
Preferred stock redeemed or repurchased (63) (5)
Dividends paid (255) (262)
Other-net (6) (15)
--------- ---------
Net cash used by financing activities (1,386) (276)
--------- ---------
Net Change in Cash and Cash Equivalents (1,047) 64
Cash and Cash Equivalents at January 1 1,397 144
--------- ---------
Cash and Cash Equivalents at June 30 $ 350 $ 208
--------- ---------
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 394 $ 315
Income taxes 209 237
<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 June 30, Six months ended June 30,
1998 1997 1998 1997
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Electric utility $ 1,708 $ 1,877 $ 3,270 $ 3,599
Gas utility 409 402 873 954
-------- -------- -------- --------
Total operating revenues 2,117 2,279 4,143 4,553
-------- -------- -------- --------
Operating Expenses
Cost of electric energy 465 597 953 1,107
Cost of gas 104 62 282 276
Operating and maintenance, net 688 802 1,414 1,463
Depreciation and decommissioning 544 448 1,074 891
Provision for regulatory adjustment mechanisms (181) - (503) -
-------- -------- -------- --------
Total operating expenses 1,620 1,909 3,220 3,737
-------- -------- -------- --------
Operating Income 497 370 923 816
Interest expense, net 165 147 333 291
Other income and (expense) 30 14 71 23
-------- -------- -------- -------
Income Before Income Taxes 362 237 661 548
Income taxes 169 107 312 245
-------- -------- -------- -------
Net Income 193 130 349 303
Preferred dividend requirement and
redemption premium 7 8 15 17
-------- -------- -------- -------
Income Available for Common Stock $ 186 $ 122 $ 334 $ 286
======== ======== ======== =======
<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
June 30, December 31,
1998 1997
----------- -----------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 77 $ 80
Short-term investments 21 1,143
Accounts receivable
Customers, net 1,124 1,204
Regulatory balancing accounts 590 658
Related parties accounts receivable 496 459
Inventories and prepayments 489 523
-------- --------
Total current assets 2,797 4,067
Property, Plant, and Equipment
Electric 17,705 17,246
Gas 7,031 6,939
-------- --------
Total property, plant, and equipment (at original cost) 24,736 24,185
Accumulated depreciation and decommissioning (11,638) (11,134)
-------- --------
Net property, plant, and equipment 13,098 13,051
Other Noncurrent Assets
Regulatory assets 6,293 6,646
Nuclear decommissioning funds 1,098 1,024
Other 332 359
-------- --------
Total noncurrent assets 7,723 8,029
-------- --------
TOTAL ASSETS $ 23,618 $ 25,147
======== ========
LIABILITIES AND EQUITY
Current Liabilities
Current portion of long-term debt $ 430 $ 580
Current portion of rate reduction bonds 289 125
Accounts payable
Trade creditors 390 441
Related parties 47 134
Other 401 424
Accrued taxes 383 229
Deferred income taxes 36 149
Other 474 527
-------- --------
Total current liabilities 2,450 2,609
Noncurrent Liabilities
Long-term debt 5,878 6,218
Rate reduction bonds 2,511 2,776
Deferred income taxes 3,260 3,304
Deferred tax credits 316 338
Other 1,742 1,810
-------- --------
Total noncurrent liabilities 13,707 14,446
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 184 257
Common stock 4,132 4,582
Reinvested earnings 2,563 2,671
-------- --------
Total stockholders' equity 7,024 7,655
Commitments and Contingencies (Notes 2 and 4) -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 23,618 $ 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 six months ended June 30, 1998 1997
-------- --------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 349 $ 303
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning, and amortization 1,135 949
Deferred income taxes and tax credits-net (79) (111)
Other deferred charges and noncurrent liabilities (211) 25
Provision for regulatory adjustment mechanisms (503) -
Net effect of changes in operating assets
and liabilities:
Accounts receivable 43 -
Regulatory balancing accounts receivable 365 (41)
Inventories 19 -
Accounts payable (45) (155)
Accrued taxes 154 113
Other working capital (58) (168)
Other-net 13 13
--------- ---------
Net cash provided by operating activities 1,182 928
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (671) (743)
Other-net 83 (114)
--------- ---------
Net cash used by investing activities (588) (857)
--------- ---------
Cash Flows From Financing Activities
Common stock repurchased (800) -
Long-term debt issued - 44
Long-term debt matured, redeemed, or repurchased-net (618) (316)
Short-term debt issued (redeemed)-net - 497
Preferred stock redeemed or repurchased (65) -
Dividends paid (230) (362)
Other-net (6) (8)
--------- ---------
Net cash used by financing activities (1,719) (145)
Net Change in Cash and Cash Equivalents (1,125) (74)
Cash and Cash Equivalents at January 1 1,223 144
--------- ---------
Cash and Cash Equivalents at June 30 $ 98 $ 70
--------- ---------
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 315 $ 277
Income taxes 260 243
<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 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. PG&E Corporation had previously announced
that it was evaluating its Australian holdings in light of its intention to
focus on its national energy strategy.
The sale to DEI represents a premium on the price in local currency of
PG&E 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.
In 1997, the Corporation agreed to acquire, through its subsidiary U.S.
Generating (USGen), 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
<PAGE>
previously committed to by NEES. Including fuel and other inventories and
transaction costs, the Corporation expects financing requirements to total
approximately $1.805 billion, to be funded through $1.38 billion of USGen
debt and a $425 million equity contribution. The assets include
hydroelectric, coal, oil, and natural gas generation facilities with a
combined generating capacity of 4,000 megawatts (MW) and 23 multi-year power
purchase agreements representing an additional 1,100 MW of production
capacity. The Corporation expects to complete the acquisition in the third
quarter of 1998.
The Corporation agreed to acquire these 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 took effect March 1, 1998. However, a referendum
to repeal this legislation is on the November ballot. If the voters approve
the referendum, then the restructuring legislation in Massachusetts may be
repealed. As Massachusetts represents only a portion of the New England
market, the Corporation does not expect that any repeal will have a material
impact on its results of operations or financial position.
In addition, as discussed below in Utility Generation Divestiture, as
part of electric industry restructuring, the California Public Utilities
Commission (CPUC) has been informed that the Utility does not intend to
retain any of its remaining non-nuclear generation facilities as part of the
Utility.
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.
Additionally, 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 in the Statement of Consolidated Income.
The Utility manages price risk independently from the activities in the
Corporation's unregulated businesses. 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 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 of 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
<PAGE>
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. Furthermore, 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.
As stated above, the Corporation utilizes the mark-to-market method of
accounting for its non-hedging commodity trading and price risk management
activities. Accordingly, 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.
Unrealized gains and losses and related reserves are recorded as inventories
and prepayments and other liabilities.
The Corporation's net gains and losses associated with price risk
management activities for the three- and six- month periods ended June 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 will adopt the new Statement by 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
that are not hedges must be adjusted to fair value through income. If the
derivative is a 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 ineffective portion of a
derivative's change in fair value will be immediately recognized in
earnings.
The Corporation is currently 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 can choose an energy service provider who will provide their
electric generation power. Customers within the Utility's service territory
can purchase electricity: (1) from the Utility; (2) from retail electricity
providers (for example, marketers including our energy service subsidiary,
<PAGE>
brokers, and aggregators); or (3) directly from unregulated power
generators. The Utility will 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 is an open
electric marketplace where electricity prices are set. The ISO, under the
jurisdiction of the Federal Energy Regulatory Commission (FERC), oversees
California's electric transmission grid ensuring that all users have
comparable access. California utilities, while retaining ownership of
utility transmission facilities, have relinquished operating control to the
ISO. Starting March 31, 1998, the ISO has scheduled the delivery of
regulatory "must-take" resources such as Qualifying Facilities (QFs) and
Diablo Canyon Nuclear Power Plant (Diablo Canyon). After scheduling must-
take resources, the ISO satisfies the remaining aggregate demand from the PX
and purchases necessary generation and ancillary services to maintain grid
reliability. To meet the demand, the PX accepts the lowest bids from
competing electric providers and 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 purchase all electric power for
its retail customers from the PX or from must-take resources. Excluding
must-take resources, the Utility must sell all of its generated electric
power to the PX. During the second quarter of 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 as follows:
For the three
months ended
June 30, 1998
Cost of electric generation 502
Cost of purchase from PX 110
Proceeds from sales to PX (147)
------
Cost of electric energy 465
Utility cost of gas 104
------
Cost of energy for Utility 569
Electric Transition Plan:
- -------------------------
In developing state legislation to implement a competitive market, it was
recognized that the Utility's market-based revenues would not be sufficient
to recover (that is, to collect from customers) all generation costs
resulting from past CPUC decisions. To recover these uneconomic costs,
called transition costs, and to ensure a smooth transition to the
competitive environment, the Utility, in conjunction with other California
electric utilities, the CPUC, state legislators, consumer advocates, and
others, developed a transition plan, 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 Voter Initiative, the November 1998 California ballot
will include provisions to overturn major portions of the current electric
utility restructuring legislation and could have a material adverse impact
on the Utility.
<PAGE>
There are two principle 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 has established a transition
period, which continues until the earlier of March 31, 2002, or when the
Utility has recovered its authorized transition costs as determined by the
CPUC. 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:
- -------------------------------
The first element of the transition plan established by the restructuring
legislation is an electric rate freeze and an electric 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. 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 six- month periods ended June 30,
1998, the electric rate reduction caused operating revenues to decrease by
approximately $86 million and $180 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 financed $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. We expect to recover the transition
costs associated with the rate reduction bonds over the term of the bonds.
Transition Cost Recovery:
- -------------------------
The second element of the transition plan established by the restructuring
legislation is recovery of transition costs. Transition costs are costs
that are 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 Qualifying
Facilities (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 are currently included
in the Utility customers' rates. Above-market facility costs are those
facilities whose book values are expected to be in excess of their market
values. Conversely, below-market facility costs are those whose market
values are expected to be in excess of their book values. 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 being collected in rates.
<PAGE>
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, spin, 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.
Costs associated with the Utility's long-term contracts to purchase power
at above-market prices from QFs and other power suppliers are also 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 term of the contract.
Generation-related regulatory assets, net of regulatory obligations, are
also eligible for transition cost recovery. As of June 30, 1998, the
Utility has accumulated approximately $6.3 billion of these assets net of
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 March 31, 2002. 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 March 31,
2002, 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 the
facility. During the rate freeze, the FTA and nuclear decommissioning
charges will not increase the Utility customers' electric rates. Excluding
these exceptions, the Utility will write-off any transition costs not
recovered during the transition period.
The restructuring legislation gives the CPUC ultimate authority to
determine the recoverable amount of transition costs. With this authority,
the CPUC will review transition costs to determine reasonableness throughout
the transition period. In addition, the CPUC is conducting a financial
verification audit of the Utility's Diablo Canyon accounts at December 31,
1996. 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
<PAGE>
with Utility-owned generating facilities that are fixed and unavoidable and
currently included in the Utility customers' electric rates.) The CPUC will
hold a proceeding to review the results of the audit, including any proposed
adjustments to the recovery of Diablo Canyon costs in rates. Transition
costs disallowed by the CPUC for collection from Utility customers will be
written-off and may result in a material charge. At this time, the amount
of transition cost disallowances, if any, cannot be predicted.
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. The amortization and
depreciation of transition costs exceeded associated revenues for the three-
and six- month periods ended June 30, 1998, by $181 million and $503
million, respectively. In accordance with CPUC rate treatment of transition
costs, the Utility deferred this excess as a regulatory asset.
The Utility's ability to recover its transition costs during the
transition period will be dependent on several factors. These factors
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. Based upon its current
evaluation of these factors, the Corporation believes that the Utility will
recover its transition costs. However, a change in one or more of these
factors, including voter approval of Proposition 9 discussed below, could
affect the probability of recovery of transition costs and result in a
material charge.
Utility Generation Divestiture:
- -------------------------------
To alleviate market power concerns of the CPUC, the Utility has agreed to
sell its fossil-fueled generation facilities.
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 have a
combined book value at July 1, 1998, of approximately $351 million and a
combined capacity of 2,645 megawatts (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 of San Francisco to
withdraw from the auction process the Hunters Point Power Plant and
permanently close it when reliable alternative electricity resources are
operational. This agreement with the City of San Francisco is subject to
CPUC approval. Hunters Point is a fossil-fueled plant with a generating
capacity of 423 MW and a book value, including plant-related regulatory
assets, at June 30, 1998, of $42 million.
<PAGE>
The Utility will proceed with the auction and sale of its remaining
fossil-fueled and geothermal facilities, Potrero, Pittsburg, Contra Costa,
and Geysers power plants. These remaining fossil-fueled and geothermal
facilities have a combined generating capacity of 4,289 MW and a combined
book value at June 30, 1998, of approximately $688 million. On August 5,
1998, the CPUC issued a draft environmental impact report on the Utility's
proposed sale of these plants. Comments on the draft environmental impact
report are due on September 21, 1998. The Utility expects to receive final
bids to purchase these plants during the fourth quarter of 1998, subject to
CPUC approval. The Utility expects that the sale of these plants will be
completed during 1999.
During the transition period, the proceeds 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.
The Utility informed the CPUC that it does not intend to retain its
remaining 4,000 MW of fossil-fueled and hydroelectric facilities as part of
the Utility. These remaining facilities have a combined book value,
including plant-related regulatory assets, at June 30, 1998, of
approximately $1.5 billion. The Utility expects to announce a plan for
disposition of these facilities in the third quarter of 1998. As previously
mentioned, any plan for 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 are 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
<PAGE>
required by EITF 97-4. Accordingly, at June 30, 1998, this amount has been
reclassified from Property, Plant, and Equipment to Regulatory assets on the
accompanying balance sheets. In addition, prior year balances have been
reclassified.
California Voter Initiative:
- ----------------------------
On November 24, 1997, various consumer groups filed a voter initiative
(Proposition 9) with the California Attorney General that would overturn
major provisions of California's electric industry restructuring legislation
discussed above. On June 24, 1998, the California Secretary of State
announced that Proposition 9 had qualified for the November 1998 statewide
ballot.
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, including the Utility, would ensue. Although the
Corporation believes the arguments in litigation challenging Proposition 9
would be compelling, no assurances can be given whether or when Proposition
9 would be overturned.
In addition to the potential impacts on the Utility discussed below, any
such litigation 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, if an immediate stay is not granted. Even if a stay is granted,
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, which would permit acceleration of the maturity of the
rate reduction bonds. 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.
If Proposition 9 is approved and implemented, 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 and
certain investments in electric generation plant which would no longer be
probable of recovery because of reductions in future revenues. The Utility
anticipates that such a write-off could amount to approximately $2 billion
after-tax, or, based on conservative assumptions, $3 billion after-tax.
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
<PAGE>
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 from 1999 through
2001 (based on current frozen rates which would otherwise be in effect and
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 affect
the Utility's electric revenues.
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 $18 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 $8.7 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 $159 million per incident, with payments in
each year limited to a maximum of $20 million per incident.
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.
<PAGE>
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. It is reasonably possible that a
change in the estimate will 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 June 30, 1998, of $263 million for
hazardous waste remediation costs at identified sites, including fossil-
fueled power plants. Environmental remediation at identified sites may be
as much as $474 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 $263 million liability, discussed above, the Utility has recovered
$80 million and expects to recover $156 million in future rates.
Additionally, the Utility is seeking recovery of its costs from insurance
carriers and from other third parties as appropriate.
Further, as discussed in Utility Generation Divestiture above, the
Utility will retain the pre-closing remediation liability associated with
divested generation facilities.
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.
Helms Pumped Storage Plant (Helms):
- -----------------------------------
Helms is a three-unit hydroelectric combined generating and pumped storage
plant. At June 30, 1998, the Utility's net investment was $626 million.
As part of the 1996 General Rate Case decision in December 1995, the CPUC
directed the Utility to perform a cost-effectiveness study of Helms. In
July 1996, the Utility submitted its study, which concluded that the
continued operation of Helms is cost effective. The Utility recommended
that the CPUC take no action and address Helms along with other generating
plants in the context of electric industry restructuring.
Under electric industry restructuring, Helms' sunk costs are eligible for
recovery as a transition cost. Ongoing operating costs of the facility are
at risk for recovery through the newly restructured electric generation
market.
Because the CPUC has not specifically addressed the cost-effectiveness
study, the Utility is currently unable to predict whether there will be
further changes in cost recovery. The Corporation believes that the
<PAGE>
ultimate outcome of this matter will not have a material impact on its or
the Utility's financial position or results of operations.
The Corporation has also informed the CPUC that it does not intend to
retain Helms as part of the Utility. See Utility Generation Divestiture
above.
Stock Repurchase Program:
- -------------------------
In January 1998, the Corporation repurchased in a specific transaction 37
million shares of PG&E Corporation common stock at $30.3125 per share. In
connection with this transaction, the Corporation entered into a forward
contract with an investment institution. The Corporation will retain the
risk of increases and the benefit of decreases in the price of the common
shares purchased through the forward contract. This obligation will not be
terminated until the investment institution replaces the shares sold to the
Corporation through purchases on the open market or through privately
negotiated transactions. The Corporation anticipates that the contract will
expire by December 31, 1998. The Corporation may settle this additional
obligation in either shares of stock or cash. The Corporation does not
expect the program to have a material impact on the Corporation'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.
In 1998, the court dismissed 240 plaintiffs' claims; the dismissals are
subject to possible appeal. In other cases, the courts dismissed more than
100 additional plaintiffs' claims for failure to respond to discovery or
otherwise pursue their claims. Also in 1998, various court rulings were
issued finding that certain of the claims are not recognizable under
California law. Currently, there are claims pending on behalf of
approximately 2,300 individuals.
The Utility is responding to the suits and asserting affirmative
defenses. One of the cases, involving 40 plaintiffs, is scheduled for trial
beginning December 7, 1998, in San Francisco. 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.
<PAGE>
GTT and various of its affiliates are defendants in at least two class
action suits and six separate suits filed by various Texas cities. The
class action suits involve classes of every municipality in Texas (excluding
certain cities that filed separate suits) in which any of the defendants
engaged in business activities related to natural gas or natural gas
liquids, sold or supplied gas, or used public rights-of-way. 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.
The Corporation believes that the ultimate outcome of these matters will
not have a material impact on its financial position.
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.
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 Form 10-K.
In this MD&A, we explain the results of operations for the three- and
six- month periods ended June 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.
<PAGE>
This Quarterly Report on 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 important factors that could affect future results and that could
cause actual results to differ materially from those expressed in the
forward looking statements, or from historical results, include, but are not
limited to: (1) the ongoing restructuring of the electric and gas industries
in California and nationally; (2) the continued application of the
regulatory framework established by the California Public Utilities
Commission (CPUC) and state legislation; (3) the outcome of the regulatory
proceedings related to the restructuring; (4) the outcome of Proposition 9;
(5) our 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; (6) the planned sale of the Utility-
owned fossil-fueled electric generating plants; (7) the impact of our
planned acquisition of the New England Electric System (NEES) assets; (8)
the approval of our Utility's 1999 General Rate Case application resulting
in the Utility's ability to earn its authorized rate of return; (9)
increased competition; (10) our ability to expand into new markets and to
compete successfully in those markets; (11) fluctuations in the prices of
commodity gas and electricity and our ability to successfully hedge against
such price risk; and (12) the potential impact from internal or external
Year 2000 problems. 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 six- month periods ended June 30, 1998, and 1997. We then explain why
operating revenues and expenses varied from 1998 to 1997.
The following table shows our results of operations for the three- and
six- month periods ended June 30, 1998, and 1997, and total assets at June
30, 1998, and 1997. The results of operations for PG&E Corporation on a
stand-alone basis and intercompany eliminations have been shown as Corporate
and Other.
<TABLE>
(in millions)
<CAPTION>
Unregulated Corporate
Business and
Utility Operations Other Total
-------- ------------ --------- -------
<S> <C> <C> <C> <C>
For the three months ended
June 30,
1998
Operating revenues $ 2,117 $ 2,851 $ (181) $ 4,787
Operating expenses 1,620 2,788 (181) 4,227
------- ------- ------ -------
Operating income (loss)
before income taxes 497 63 - 560
Income available for
common stock 186 (5) (7) 174
1997
Operating revenues $ 2,279 $ 815 $ (11) $ 3,083
Operating expenses 1,909 813 (10) 2,712
------- ------- ------- -------
Operating income (loss)
before income taxes 370 2 (1) 371
Income available for
common stock 122 77 (6) 193
For the six months ended
June 30,
1998
Operating revenues $ 4,143 $ 5,334 $ (337) $ 9,140
Operating expenses 3,220 5,231 (337) 8,114
------- ------- ------ -------
Operating income (loss)
before income taxes 923 103 - 1,026
Income available for
common stock 334 (1) (20) 313
Total assets at June 30 $23,618 $ 6,520 $ (849) $29,289
1997
Operating revenues $ 4,553 $ 1,920 $ (24) $ 6,449
Operating expenses 3,737 1,897 (20) 5,614
------- ------- ------- -------
Operating income (loss)
before income taxes 816 23 (4) 835
Income available for
common stock 286 87 (8) 365
Total assets at June 30 $23,531 $ 3,439 $ (295) $26,675
</TABLE>
<PAGE>
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.
The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay
the Corporation. At June 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, see the
discussion of the California Voter Initiative below and its potential impact
on future earnings.
Earnings Per Common Share:
- --------------------------
Earnings per common share for the three- and six- month periods ended June
30, 1998, decreased $.03 and $.09 cents, respectively, as compared to the
same periods in 1997. The activity discussed below affected earnings per
common share.
Utility Results:
- ----------------
Utility operating revenues for the three- and six- month periods ended June
30, 1998, decreased $162 million and $410 million, respectively, as compared
to the same periods in 1997. Operating revenues declined due to: (1) a 10
percent electric rate reduction, discussed below, provided to residential
and small commercial customers, which caused a decrease of $86 million and
$180 million for both the three- and six- month periods ended June 30, 1998,
respectively; (2) the termination of our volumetric (ERAM) and energy cost
(ECAC) revenue balancing accounts, which totaled approximately $96 million
in the six-month period ended June 30, 1997, (we 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); (3) a decrease in usage and sales to medium and large
electric customers resulting from the effects of competition; and (4) 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 decreased $289 million and $517 million,
respectively, for the three- and six- month periods ended June 30, 1998, as
compared to the same periods in 1997. Operating expenses declined primarily
as a result of lower gas prices, lower transmission pipeline demand charges,
the lack of a refueling outage at Diablo Canyon Power Plant (Diablo Canyon),
and 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
the summer months. Others relate to transition costs which will be
recovered after the conclusion of the transition period.
<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 six- month periods ended June 30, 1998,
increased approximately $2.0 billion and $3.4 billion, respectively, while
operating expenses also increased approximately $2.0 billion and $3.3
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 gross operating margin
increases, however, were partially offset by decreases in our gas
transmission operating margins due to low transmission and natural gas
liquids prices in Texas. Unregulated business operations contributed $82
million and $88 million less, respectively, in net income in the three- and
six- month periods ended June 30, 1998, than in the same periods in 1997,
primarily due to the sale of our Australian holdings (See Acquisitions and
Sales, below.) In addition, in the second quarter of 1997, the Corporation
recognized a $110 million gain on the sale of its interest in Intergen,
which was partially offset by write-offs of 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
planned 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 can choose an energy service provider who will provide their
electric generation power. Customers within our Utility's service territory
can purchase electricity: (1) from our 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 will 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 is an
open electric marketplace where electricity prices are set. The ISO, under
the jurisdiction of the Federal Energy Regulatory Commission (FERC),
oversees California's electric transmission grid, ensuring that all
generators have comparable access. California utilities, while retaining
ownership of utility transmission facilities, have relinquished operating
control to the ISO. Starting March 31, 1998, the ISO has scheduled the
delivery of regulatory "must-take" resources such as Qualifying Facilities
(QFs) and Diablo Canyon. After scheduling must-take resources, the ISO
satisfies the remaining aggregate demand from the PX and purchases necessary
generation and ancillary services to maintain grid reliability. To meet the
demand, the PX accepts the lowest bids from competing electric providers and
<PAGE>
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 our Utility to purchase all electric power for
its retail customers from the PX or from must-take resources. Excluding
must-take resources, we must sell all of our Utility-generated electric
power to the PX. During the second quarter of 1998, the Cost of Energy for
our 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 as follows:
For the three
months ended
June 30, 1998
Cost of electric generation 502
Cost of purchase from PX 110
Proceeds from sales to PX (147)
-------
Cost of electric energy 465
Utility cost of gas 104
-------
Cost of energy for Utility 569
Electric Transition Plan:
- -------------------------
Over the past several years, we have been taking steps to prepare for
competition in the electric generation business. We have been working 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, it was
recognized that our Utility's market-based revenues would not be sufficient
to recover (that is, to collect from customers) all generation costs
resulting from past CPUC decisions. To recover these uneconomic costs,
called transition costs, and to ensure a smooth transition to the
competitive environment, our Utility in conjunction with other California
electric utilities, the CPUC, state legislators, consumer advocates, and
others, developed a transition plan, 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 Voter Initiative, the November 1998 California ballot
will include provisions to overturn major portions of the current electric
utility restructuring legislation and could have a material adverse impact
on the Utility.
There are two principle elements to 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 has established a transition
period, which continues until the earlier of March 31, 2002, or when the
Utility has recovered its authorized transition costs as determined by the
CPUC. 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:
- -------------------------------
The first element of the transition plan established by restructuring
legislation is an electric rate freeze and an electric rate reduction.
During 1997, electric rates for our Utility's customers were held at 1996
levels. Effective January 1, 1998, we reduced electric rates for our
Utility's residential and small commercial customers by 10 percent and will
hold their rates at that level. 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 six- month periods ended June
30, 1998, the rate reduction caused operating revenues to decrease by
approximately $86 million and $180 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 financed $2.9 billion of our 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. We expect to recover the transition
costs associated with the rate reduction bonds over the term of the bonds.
Transition Cost Recovery:
- -------------------------
The second element of the transition plan, established by restructuring
legislation, is recovery of transition costs. Transition costs are costs
that are 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 are currently included
in our Utility customers' rates. Above-market facility costs are those
facilities whose book values are expected to be in excess of their market
values. Conversely, below-market facility costs are those whose market
values are expected to be in excess of their book values. 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 being collected in rates.
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, spin, or sale) is completed for each of our
Utility's generation facilities. The first of these valuations occurred on
July 31, 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.
Costs associated with the Utility's long-term contracts to purchase power
at above-market prices from QFs and other power suppliers are also eligible
to be recovered as transition costs. Our Utility has agreed to purchase
<PAGE>
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, our Utility expects to collect
the difference between the contract price and the market price from
customers, as a transition cost, over the term of the contract.
Generation-related regulatory assets, net of regulatory obligations, are
also eligible for transition cost recovery. As of June 30, 1998, the
Utility has accumulated approximately $6.3 billion of these assets net of
obligations including the amounts reclassified from Property, Plant, and
Equipment, discussed in Utility Generation Impairment below.
The restructuring legislation specifies that most transition costs must
be recovered by March 31, 2002. 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,
we are receiving a reduced return for all of our 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 March 31,
2002, the Utility may include certain transition costs 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 the facility. During the rate freeze, the FTA and
nuclear decommissioning charges will not increase the Utility customers'
electric rates. Excluding these exceptions, the Utility will write-off any
transition costs not recovered during the transition period.
The restructuring legislation gives the CPUC ultimate authority to
determine the recoverable amount of transition costs. With this authority,
the CPUC will review transition costs to determine the reasonableness
throughout the transition period. In addition, the CPUC is conducting a
financial verification audit of the Utility's Diablo Canyon accounts at
December 31, 1996. 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 CPUC will hold a proceeding to review the results of the audit,
including any proposed adjustments to the recovery of Diablo Canyon costs in
rates. Transition costs disallowed by the CPUC for collection from Utility
customers will be written-off and may result in a material charge. At this
time, the amount of disallowance of transition costs, if any, cannot be
predicted.
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
<PAGE>
frozen rates for transition cost recovery is subject to seasonal
fluctuations in the Utility's sales volumes. The amortization and
depreciation of transition costs exceeded associated revenue for the three-
and six- month periods ended June 30, 1998, by $181 million and $503
million, respectively. In accordance with CPUC rate treatment of transition
costs, the Utility deferred this excess as a regulatory asset.
The Utility's ability to recover its transition costs during the
transition period will be dependent on several factors. These factors
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
our Utility-owned generation facilities; (4) future Utility sales levels;
(5) future Utility fuel and operating costs; (6) the extent to which our
Utility's authorized revenues to recover distribution costs are increased or
decreased; and (7) the market price of electricity. Based upon its
evaluation of these factors, the Corporation believes that the Utility will
recover its transition costs. However, a change in one or more of these
factors, including voter approval of Proposition 9 discussed below, could
affect the probability of recovery of transition costs and result in a
material charge.
Utility Generation Divestiture:
- -------------------------------
To alleviate market power concerns of the CPUC, we have agreed to sell our
fossil-fueled generation facilities.
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 have a
combined book value at July 1, 1998, of approximately $351 million and a
combined capacity of 2,645 megawatts (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 of San Francisco to
withdraw from the auction process the Hunters Point Power Plant and
permanently close it when reliable alternative electricity resources are
operational. This agreement with the City of San Francisco is subject to
CPUC approval. Hunters Point is a fossil-fueled plant with a generating
capacity of 423 MW and a book value, including plant-related regulatory
assets, at June 30, 1998, of $42 million.
The Utility will proceed with the auction and sale of its remaining
fossil-fueled and geothermal facilities, Potrero, Pittsburg, Contra Costa,
and Geysers power plants. These remaining fossil-fueled and geothermal
facilities have a combined generating capacity of 4,289 MW and a combined
book value at June 30, 1998, of approximately $688 million. On August 5,
1998, the CPUC issued a draft environmental impact report on the Utility's
proposed sale of these plants. Comments on the draft environmental impact
report are due on September 21, 1998. The Utility expects to receive final
bids to purchase these plants during the fourth quarter of 1998, subject to
CPUC approval. The Utility expects that the sale of these plants will be
completed during 1999.
<PAGE>
During the transition period, the proceeds 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.
The Utility informed the CPUC that it does not intend to retain its
remaining 4,000 MW of fossil-fueled and hydroelectric facilities as part of
the Utility. These remaining facilities have a combined book value,
including plant-related regulatory assets, at June 30, 1998, of
approximately $1.5 billion. Our Utility expects to announce a plan for the
disposition of the facilities in the third quarter of 1998. As previously
mentioned, any plan for 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) 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 are 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 has been
reclassified from Property, Plant, and Equipment to Regulatory assets on the
accompanying balance sheets. In addition, prior year balances have been
reclassified.
Customer Impacts of Transition Plan:
- ------------------------------------
Effective March 31, 1998, all Californians may choose their electric
commodity provider. As of July 31, 1998, our Utility had accepted
approximately 55,000 requests to switch their electric commodity supplier
from the Utility to another electric commodity provider.
<PAGE>
Regardless of the customer's choice of electric commodity provider,
during the transition period, all 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 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 will
then 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 Utility's or
our financial condition or results of operations.
California Voter Initiative:
- ----------------------------
On November 24, 1997, various consumer groups filed a voter initiative
(Proposition 9) with the California Attorney General that would overturn
major provisions of California's electric industry restructuring legislation
discussed above. On June 24, 1998, the California Secretary of State
announced that Proposition 9 had qualified for the November 1998 statewide
ballot.
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.
On May 22, 1998, a group known as "Californians for Affordable and
Reliable Electric Services" (CARES) filed a petition in the California Third
District Court of Appeal to exclude Proposition 9 from the November 1998
ballot on the grounds that it represents an unconstitutional impairment of
contract rights and that it is an unconstitutional attempt to implement
actions by statute that only can be done through a state constitutional
amendment. Supporters of CARES include the California State Chamber of
Commerce, the state's investor-owned utilities (including Pacific Gas and
Electric Company), and a wide range of business, environmental, and consumer
groups. On July 2, 1998, the Court denied the CARES petition. CARES
<PAGE>
appealed the decision to the California Supreme Court and the court denied
the appeal without comment. Neither court ruled on the merits of the case,
leaving open the option of legal action following the election.
If the voters approve Proposition 9, further legal challenges by the
California utilities, including the Utility, would ensue. Although the
Corporation believes the arguments in litigation challenging Proposition 9
would be compelling, no assurances can be given whether or when Proposition
9 would be overturned.
In addition to the potential impacts on the Utility discussed below, any
such litigation 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, if an immediate stay is not granted. Even if a stay is granted,
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, which would permit acceleration of the maturity of the
rate reduction bonds. 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.
If Proposition 9 is approved and implemented, 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 and
certain investments in electric generation plant which would no longer be
probable of recovery because of reductions in future revenues. The Utility
anticipates that such a write-off could amount to approximately $2 billion
after-tax, or, based on conservative assumptions, $3 billion after-tax.
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 from 1999 through
2001 (based on current frozen rates which would otherwise be in effect and
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.
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 to be effective October 30, 1998.
All 1998 retail electric transmission revenues are subject to refund pending
<PAGE>
further analysis 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 the construction of duplicative electric
distribution facilities to allow competition within the electric
distribution market. We believe that these regulatory pronouncements
contradict prior CPUC policy on duplicative distribution facilities and that
these pronouncements have increased substantially the uncertainty
surrounding the future role of California's utility distribution companies.
In addition, we believe that the CPUC made these regulatory pronouncements
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
impacts of duplicate distribution facilities; and (4) the distribution
utilities' statutory obligation to serve. At this time, we cannot predict
the extent that the CPUC will encourage the future construction of
duplicative distribution facilities or the impact that future duplicative
distribution facilities and increased competition will have on our or 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 rule-making proceeding to further
expand market-oriented policies in California's gas industry. Policies
under consideration include the additional unbundling of services,
streamlining regulation for noncompetitive services, mitigating the
potential for anti-competitive behavior, and establishing appropriate
consumer protections. The CPUC is currently studying new alternative market
structures with the goal of encouraging competition and customer choice,
while maintaining a high standard of consumer protection.
On August 6, 1998, the CPUC directed its Energy Division to prepare
proposed consumer protection guidelines for the restructuring of the natural
gas industry. The CPUC stated that it intends to issue a proposed market
structure decision after it reviews various reports and materials scheduled
to be completed this summer and fall. The CPUC also directed utilities to
file applications identifying gas cost functional categories, due February
26, 1999. However, on August 12, 1998, the California legislature passed
Senate Bill (SB) 1602, which requires legislative approval of any CPUC
decisions regarding gas unbundling issued after July 1, 1998. SB 1602
awaits the Governor's signature. At this point, we cannot predict the
outcome of these proceedings and their impact on our financial position and
results of operations.
<PAGE>
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) conduct
and supervise an audit of transactions between the Utility and its
affiliates from 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 to determine if the additional recommended
conditions should be imposed on PG&E Corporation are scheduled to begin in
the second half of 1998. 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
material 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. PG&E Corporation had previously announced
that it was evaluating its Australian holdings in light of its intention to
focus on its national energy strategy .
The sale to DEI represents a premium on the price in local currency of
our 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.
In 1997, the Corporation agreed to acquire, through its subsidiary USGen,
a portfolio of electric generating assets and power supply contracts from
NEES for $1.59 billion, plus $85 million for early retirement and severance
costs previously committed to by NEES. Including fuel and other inventories
and transaction costs, the Corporation expects financing requirements to
total approximately $1.805 billion, to be funded through $1.38 billion of
USGen debt and a $425 million equity contribution. The assets include
hydroelectric, coal, oil, and natural gas generation facilities with a
combined generating capacity of 4,000 MW and 23 multi-year power purchase
agreements representing an additional 1,100 MW of production capacity. The
<PAGE>
Corporation expects to complete the acquisition in the third quarter of
1998.
The Corporation agreed to acquire these 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 took effect March 1, 1998. However, a referendum
to repeal this legislation is on the November ballot. If the voters approve
the referendum, then the restructuring legislation in Massachusetts may be
repealed. As Massachusetts represents only a portion of the New England
market, the Corporation does not expect that any repeal will have a material
impact on its results of operation or financial position.
In addition, as discussed above in Utility Generation Divestiture, as
part of electric industry restructuring, the CPUC has been informed that the
Utility does not intend to retain any of its remaining non-nuclear
generation facilities as part of the Utility.
YEAR 2000:
The Year 2000 issue exists because many software products use only two
digits to identify a year in the date field and were developed without
considering the impact of the upcoming change in the century. Some of these
software products are critical to our operations and business processes and
might fail or function incorrectly if not repaired or replaced with Year
2000 compliant products. In addition, many electronic monitoring and
control systems have two-digit date coding embedded within their circuitry
and may also be susceptible to failure or incorrect operation unless
corrected or replaced with Year 2000 compliant products.
Currently, we are focusing our efforts to be Year 2000 ready on those
software and embedded systems, which are critical to our business. We
expect to complete remediation of the critical software systems by the end
of 1998 and to complete testing of these systems by the third quarter of
1999. Although we have completed an enterprise-wide inventory of all
embedded systems to assess the degree of Year 2000 compliance, additional
embedded systems that require Year 2000 remediation may be discovered as we
begin the remediation and testing phases of our compliance effort. We
expect to complete assessment of all critical embedded systems and to repair
or replace those systems found to be non-compliant by the fourth quarter of
1999.
We also depend upon external parties including customers, suppliers,
business partners, government agencies, and financial institutions to
reliably deliver our 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. We have begun to
assess the degree to which third parties with whom we have significant
business relationships have adequate plans to address Year 2000 problems.
We expect to complete such assessment by the fourth quarter of 1998.
To the extent appropriate, we plan to develop contingency plans to reduce
the risk of material impacts on our operations from Year 2000 problems. Due
to the speculative nature of contingency planning, it is uncertain whether
such plans actually will be sufficient to reduce the risk of material
impacts on our operations due to Year 2000 problems.
Through June 30, 1998, we have spent approximately $135 million over the
past few years to assess and remediate Year 2000 problems and to replace
non-compliant software systems. In large part, these non-compliant software
systems were replaced for business purposes other than addressing Year 2000
<PAGE>
issues. The replacement costs for these systems were capitalized. The
remaining costs, including costs incurred to assess and remediate Year 2000
problems, were expensed.
Currently, we estimate that we will spend approximately $100 million in
the aggregate for the remainder of 1998 and 1999 to address Year 2000
issues, to replace non-compliant software systems, and to replace hardware
in non-compliant embedded systems and computer systems. We expect that
approximately $30 million of the estimated aggregate amount will represent
replacement costs incurred primarily for business purposes other than to
address Year 2000 issues. This amount will be capitalized. The remaining
amount, approximately $70 million, will be expensed. As we continue to
assess our systems and as the remediation and testing phases of our
compliance effort progresses, our estimated costs may increase. Further, we
expect to incur costs after the Year 1999 to remediate and replace less
critical software and embedded systems.
Our 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. Therefore, delays by third
parties may cause our schedule to change.
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. Nevertheless, achieving Year 2000 readiness is subject to various
risks and uncertainties, many of which are described 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 readiness.
However, 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 PG&E
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 six-month period ended June 30, 1998, the Corporation issued
$36 million of common stock, primarily through the Dividend Reinvestment
Plan and the Stock Option Plan. Also during the six-month period ended June
30, 1998, the Corporation paid dividends of $240 million and declared
dividends of $229 million. The Utility paid dividends of $215 million to
PG&E Corporation during the six-month period ended June 30, 1998. In July
1998, the Utility declared dividends of $100 million payable to PG&E
Corporation in July.
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
<PAGE>
common stock at $30.3125 per share. In connection with this transaction,
the Corporation entered into a forward contract with an investment
institution. The Corporation will retain the risk of increases and the
benefit of decreases in the price of the common shares purchased through the
forward contract. This obligation will not be terminated until the
investment institution replaces the shares sold to the Corporation through
purchases on the open market or through privately negotiated transactions.
We anticipate that the contract will expire by December 31, 1998. The
Corporation may settle this additional obligation in either shares of stock
or cash. The Corporation does not expect the program to have a material
impact on its financial position or results of operations.
The Corporation maintains a $500 million revolving credit facility, and
in August 1997, we entered into an additional $500 million temporary credit
facility. We use both of these credit facilities for general corporate
purposes. There were no borrowings under the credit facilities at June 30,
1998.
At June 30, 1998, the Corporation, primarily through an unregulated
business subsidiary, had $127 million of outstanding short-term bank
borrowings related to separate short-term credit facilities. The borrowings
are unrestricted as to use. The carrying amount of short-term borrowings
approximates fair value.
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 used proceeds
from the rate reduction bonds issued in December 1997, to reduce equity.
The Utility's long-term debt matured, redeemed, or repurchased during the
six month period ended June 30, 1998, amounted to $498 million. Of this
amount, $249 million related to the Utility's redemption of its 8 percent
mortgage bonds due October 1, 2025, and $186 million related to the
Utility's repurchase of its other mortgage bonds. The remaining $63 million
related primarily to the scheduled maturity of long-term debt.
In January 1998, the Utility redeemed its Series 7.44 percent 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 June 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.
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. We expect a final CPUC
decision in February 1999.
<PAGE>
As discussed above, in Transition Cost Recovery, the CPUC separately
reduced the authorized return on common equity on our Utility's
hydroelectric and geothermal generation assets to 6.77 percent, or 90
percent of the Utility's 1997 adopted cost of debt. The Utility believes
that this reduction is inappropriate and has sought a rehearing of this
decision. The Utility sought no change in the cost of capital for the
hydroelectric and geothermal generation assets in its 1999 Cost of Capital
application. The Utility will file a separate application if the rehearing
request is granted.
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 CPUC's ORA provided their revenue requirement
calculation, which supplements ORA's June 8, 1998, report on the 1999 GRC
proceeding. In the aggregate, the ORA is recommending a net increase of $5
million compared to the Utility's request for an aggregate increase of
$1.03 billion. The ORA has 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 will take place
August 24, 1998, through October 16, 1998. The administrative law judge
will consider 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 March 1999. The CPUC may accept all, part, or
none of ORA's recommendations. We cannot predict the amount of base revenue
increase or decrease the CPUC will ultimately 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 November 1998.
The 1999 GRC will not affect the authorized revenues for electric and gas
transmission services or for gas storage services. The Utility determines
the authorized revenues for each of these services 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 June 30, 1998, the Utility expects to spend $263 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 $474 million. Of the $263 million, the Utility has recovered $80
<PAGE>
million and expects to recover $156 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.
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 of 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. Furthermore, 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.
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. 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. Compressor Station Chromium Litigation
As previously disclosed in PG&E Corporation's and Pacific Gas
and Electric Company's Form 10-K for the fiscal year ended
December 31, 1997, and PG&E Corporation's and Pacific Gas and
Electric Company's Form 10-Q for the quarter ended March 31,
1998, various civil actions were filed against Pacific Gas and
Electric Company (known collectively as the "Aguayo Litigation")
in several California state courts. Each of the pending
complaints in the Aguayo Litigation, except Little and Mustafa
v. Pacific Gas and Electric Company, alleges personal injuries
and seeks compensatory and punitive damages in an unspecified
amount arising out of alleged exposure to chromium contamination
in the vicinity of Pacific Gas and Electric Company's gas
compressor stations located in Hinkley, Kettleman, and Topock,
California. The plaintiffs in the Aguayo Litigation include
current and former Pacific Gas and Electric Company employees,
residents in the vicinity of the compressor stations, and
persons who visited the compressor stations, alleging exposure
to chromium at or near the compressor stations. The plaintiffs
also include spouses of these plaintiffs who claim loss of
consortium or children of these plaintiffs who claim injury
through the alleged exposure of their parents.
On April 28, 1998, a Los Angeles Superior Court judge found that
claims by plaintiffs in Acosta v. Pacific Gas And Electric
Company who were neither personally exposed to chromium nor yet
conceived at the time of their parents' alleged exposure are not
recognizable under current California law and should be
dismissed. On June 25, 1998, the judge issued a similar order
in Aguilar v. Pacific Gas and Electric Company. The judge has
requested plaintiffs' counsel in both cases to identify those
plaintiffs whose claims are based solely upon preconception
exposure so the claims can be dismissed.
Further, during the second quarter, approximately 100 additional
plaintiffs have been dismissed from the Aguayo Litigation for
failure to respond to discovery or otherwise pursue their
claims.
The trial in Riep v Pacific Gas and Electric Company has been
continued to December 7, 1998, in San Francisco Superior Court.
The eight plaintiffs in Pettit v. Pacific Gas and Electric
Company dismissed their claims without prejudice in February
1998.
Two of the pending actions also name PG&E Corporation as a
defendant: Little and Mustafa v. Pacific Gas and Electric
Company and PG&E Corporation, and Whipple, et al. v. Pacific Gas
and Electric Company and PG&E Corporation, both pending in San
Bernardino Superior Court. Although plaintiffs in both actions
originally agreed to dismiss PG&E Corporation as a defendant, it
is not clear whether plaintiffs will voluntarily file such
dismissals.
As described above, currently there are six pending cases
comprising the Aguayo Litigation involving approximately 2300
remaining plaintiffs. As a result of the court's rulings
barring preconception claims in Acosta v. Pacific Gas and
Electric Company and Aguilar v. Pacific Gas and Electric
Company, Pacific Gas and Electric Company expects that
approximately 100 additional plaintiffs will be dismissed from
these cases. Pacific Gas and Electric Company anticipates that
plaintiffs will appeal these rulings.
The Corporation believes the ultimate outcome of the Aguayo
Litigation will not have a material adverse impact on its or
Pacific Gas and Electric Company's 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 six months ended June 30, 1998 was 2.88. Pacific
Gas and Electric Company's earnings to combined fixed charges
and preferred stock dividends ratio for the six months ended
June 30, 1998 was 2.71. 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.
B. Notice of Shareholder Proposals for 1999 Annual Meeting
In accordance with new Securities and Exchange Commission (SEC) Rule
14a-5(e), shareholder proxies obtained by the Boards of
Directors of PG&E Corporation and Pacific Gas and Electric
Company in connection with their 1999 annual meetings of
shareholders will confer on the proxyholders discretionary
authority to vote on any matters presented at the meetings,
unless notice of the matter is provided to the Vice President
and Corporate Secretary of PG&E Corporation or Pacific Gas and
Electric Company, or both (as may be applicable depending on
whether the matter relates to PG&E Corporation or Pacific Gas
and Electric Company, or both) no later than January 16, 1999.
As stated in the 1998 joint proxy statement, any proposal by a
shareholder to be submitted for possible inclusion in proxy
soliciting materials (in accordance with the process established
by SEC Rule 14a-8) for the 1999 annual meetings of shareholders
of PG&E Corporation and Pacific Gas and Electric Company must be
received by the Vice President and Corporate Secretary no later
than November 2, 1998.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges 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
June 30, 1998 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
June 30, 1998 for Pacific Gas and Electric
Company
(b) Reports on Form 8-K during the second quarter of 1998 and
through the date hereof (1):
1. July 10, 1998
Item 5. Other Events
A. Electric Industry Restructuring
1. Voter Initiative
2. Divestiture
B. Pacific Gas and Electric Company's General Rate Case
Proceeding
C. Sale of Australian Assets
<PAGE>
2. July 16, 1998
Item 5. Other Events
A. Second 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
August 14, 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
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 June 30, 1998
for PG&E Corporation
27.2 Financial Data Schedule for the quarter ended June 30, 1998
for Pacific Gas and Electric Company
<PAGE>
<TABLE>
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
<CAPTION>
- ----------------------------------------------------------------------------------------------
Three months ended Six months ended
June 30, June 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 $ 174 $ 193 $ 313 $ 365
========== ========== ========== ==========
Average common shares outstanding 382 398 382 403
========== ========== ========== ==========
Basic EPS $ 0.46 $ 0.49 $ 0.82 $ 0.91
========== ========== ========== ==========
DILUTED EPS (1)
Earnings available for common stock $ 174 $ 193 $ 313 $ 365
========== ========== ========== ==========
Average common shares outstanding 382 398 382 403
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 383 398 383 403
========== ========== ========== ==========
Diluted EPS $ 0.46 $ 0.49 $ 0.82 $ 0.91
========== ========== ========== ==========
- ----------------------------------------------------------------------------------------------
<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>
- ---------------------------------------------------------------------------------------------------
Six Months Year ended December 31,
ended -------------------------------------------------------
(dollars in millions) June 30, 1998 1997 1996 1995 1994 1993
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 349 $ 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 312 609 555 895 837 902
Net fixed charges 352 628 683 716 729 775
-------- -------- -------- -------- -------- --------
Total Earnings $ 1,013 $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 311 $ 485 $ 574 $ 616 $ 639 $ 652
Interest on short-
term borrowings 26 101 75 83 77 88
Interest on capital leases 1 2 3 3 2 2
Capitalized Interest - 1 1 - 2 46
AFUDC Debt 8 16 7 11 11 33
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 6 24 24 3 - -
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 352 $ 629 $ 684 $ 716 $ 731 $ 821
======== ======== ======== ======== ======== ========
Ratios of Earnings to
Fixed Charges 2.88 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>
- ----------------------------------------------------------------------------------------------------
Six Months Year ended December 31,
ended -------------------------------------------------------
(dollars in millions) June 30, 1998 1997 1996 1995 1994 1993
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 349 $ 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 312 609 555 895 837 902
Net fixed charges 352 628 683 716 729 775
-------- -------- -------- -------- -------- --------
Total Earnings $ 1,013 $ 2,005 $ 1,996 $ 2,954 $ 2,570 $ 2,749
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 311 $ 485 $ 574 $ 616 $ 639 $ 652
Interest on short-
term borrowings 26 101 75 83 77 88
Interest on capital leases 1 2 3 3 2 2
Capitalized Interest - 1 1 - 2 46
AFUDC Debt 8 16 7 11 11 33
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 6 24 24 3 - -
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 352 $ 629 $ 684 $ 716 $ 731 $ 821
-------- -------- -------- -------- -------- --------
Preferred Stock Dividends:
Tax deductible dividends $ 5 $ 10 $ 10 $ 11 $ 5 $ 5
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 17 39 39 100 96 109
-------- -------- -------- -------- -------- --------
Total Preferred
Stock Dividends $ 22 $ 49 $ 49 $ 111 $ 101 $ 114
-------- -------- -------- -------- -------- --------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 374 $ 678 $ 733 $ 827 $ 832 $ 935
======== ======== ======== ======== ======== ========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.71 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> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> JUN-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 16,287
<OTHER-PROPERTY-AND-INVEST> 666
<TOTAL-CURRENT-ASSETS> 3,822
<TOTAL-DEFERRED-CHARGES> 2,742
<OTHER-ASSETS> 5,772
<TOTAL-ASSETS> 29,289
<COMMON> 5,834
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2,041
<TOTAL-COMMON-STOCKHOLDERS-EQ> 7,875
493
329
<LONG-TERM-DEBT-NET> 7,390
<SHORT-TERM-NOTES> 576
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 113
<LONG-TERM-DEBT-CURRENT-PORT> 508
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 12,005
<TOT-CAPITALIZATION-AND-LIAB> 29,289
<GROSS-OPERATING-REVENUE> 9,140
<INCOME-TAX-EXPENSE> 322
<OTHER-OPERATING-EXPENSES> 8,114
<TOTAL-OPERATING-EXPENSES> 8,114
<OPERATING-INCOME-LOSS> 1,026
<OTHER-INCOME-NET> 14
<INCOME-BEFORE-INTEREST-EXPEN> 1,040
<TOTAL-INTEREST-EXPENSE> 405
<NET-INCOME> 313
0
<EARNINGS-AVAILABLE-FOR-COMM> 313
<COMMON-STOCK-DIVIDENDS> 237
<TOTAL-INTEREST-ON-BONDS> 179
<CASH-FLOW-OPERATIONS> 1,250
<EPS-PRIMARY> 0.82
<EPS-DILUTED> 0.82
</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> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> JUN-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 13,098
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 2,797
<TOTAL-DEFERRED-CHARGES> 2,595
<OTHER-ASSETS> 5,128
<TOTAL-ASSETS> 23,618
<COMMON> 4,132
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2,563
<TOTAL-COMMON-STOCKHOLDERS-EQ> 6,695
437
329
<LONG-TERM-DEBT-NET> 5,878
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 430
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 9,849
<TOT-CAPITALIZATION-AND-LIAB> 23,618
<GROSS-OPERATING-REVENUE> 4,143
<INCOME-TAX-EXPENSE> 312
<OTHER-OPERATING-EXPENSES> 3,220
<TOTAL-OPERATING-EXPENSES> 3,220
<OPERATING-INCOME-LOSS> 923
<OTHER-INCOME-NET> 71
<INCOME-BEFORE-INTEREST-EXPEN> 994
<TOTAL-INTEREST-EXPENSE> 333
<NET-INCOME> 349
15
<EARNINGS-AVAILABLE-FOR-COMM> 334
<COMMON-STOCK-DIVIDENDS> 100
<TOTAL-INTEREST-ON-BONDS> 179
<CASH-FLOW-OPERATIONS> 1,182
<EPS-PRIMARY> 0.00
<EPS-DILUTED> 0.00
</TABLE>
