FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
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(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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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 (Address of principal
executive offices) (Zip Code) executive offices) (Zip Code)
Pacific Gas and Electric Company PG&E Corporation
(415) 973-7000 (415) 267-7000
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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
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Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common Stock Outstanding April 30, 1998:
PG&E Corporation 381,473,556 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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...........13
NOTE 4: COMMITMENTS AND CONTINGENCIES....................13
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED
RESULTS OF OPERATIONS AND FINANCIAL CONDITION.............16
RESULTS OF OPERATIONS.....................................18
Common Stock Dividend..................................18
Earnings Per Common Share..............................19
Utility Results........................................19
Unregulated Business Results...........................19
FINANCIAL CONDITION.......................................20
COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........20
THE ELECTRIC BUSINESS.....................................20
Electric Transition Plan...............................21
Rate Freeze and Rate Reduction.........................21
Transition Cost Recovery...............................21
Generation Divestiture.................................23
Customer Impacts of Transition Plan....................24
Voter Initiative.......................................25
THE GAS BUSINESS..........................................25
ACQUISITIONS AND SALES....................................26
YEAR 2000 COMPLIANCE....................................26
LIQUIDITY AND CAPITAL RESOURCES
Sources of Capital.....................................27
Utility Cost of Capital................................29
1999 General Rate Case.............................29
Environmental Matters..................................30
Legal Matters..........................................30
Risk Management Activities.............................30
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................31
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.........................................32
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......32
ITEM 5. OTHER INFORMATION.........................................36
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................36
SIGNATURE..........................................................38
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME
(in millions, except per share amounts)
Three months ended March 31,
1998 1997
--------- ---------
Operating Revenues
Utility $ 2,025 $ 2,274
Energy commodities and services 2,328 1,091
-------- --------
Total operating revenues 4,353 3,365
Operating Expenses
Cost of energy for utility 666 725
Cost of energy commodities and services 2,153 1,017
Operating and maintenance, net 508 700
Depreciation and decommissioning 561 459
-------- --------
Total operating expenses 3,888 2,901
-------- --------
Operating Income 465 464
Interest expense, net 203 160
Other income and expense (18) (20)
-------- --------
Income Before Income Taxes 280 324
Income taxes 141 151
-------- --------
Net Income $ 139 $ 173
======== ========
Weighted Average Common Shares
Outstanding 381 409
Earnings Per Common Share, Basic and Diluted $ .36 $ .42
Dividends Declared Per Common Share $ .30 $ .30
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PG&E CORPORATION
CONDENSED BALANCE SHEET (in millions)
Balance at March 31, December 31,
1998 1997
------------ ------------
ASSETS
Current Assets
Cash and cash equivalents $ 214 $ 237
Short-term investments 49 1,160
Accounts receivable
Customers, net 1,428 1,514
Regulatory balancing accounts 782 658
Energy marketing 897 830
Inventories and prepayments 600 626
-------- --------
Total current assets 3,970 5,025
Property, Plant, and Equipment
Utility 33,294 32,972
Gas transmission 3,454 3,484
Other 217 57
-------- --------
Total property, plant, and equipment (at original cost) 36,965 36,513
Accumulated depreciation and decommissioning (16,648) (16,041)
-------- --------
Net property, plant, and equipment 20,317 20,472
Other Noncurrent Assets
Regulatory assets 2,218 2,337
Nuclear decommissioning funds 1,074 1,024
Other 1,757 1,699
-------- --------
Total noncurrent assets 5,049 5,060
-------- --------
TOTAL ASSETS $ 29,336 $ 30,557
======== ========
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 135 $ 103
Current portion of long-term debt 579 659
Current portion of rate reduction bonds 106 125
Accounts payable
Trade creditors 752 754
Other 469 466
Energy marketing 777 758
Accrued taxes 482 226
Other 684 893
-------- --------
Total current liabilities 3,984 3,984
Noncurrent Liabilities
Long-term debt 7,531 7,659
Rate reduction bonds 2,776 2,776
Deferred income taxes 4,067 4,029
Deferred tax credits 328 339
Other 2,017 2,034
-------- --------
Total noncurrent liabilities 16,719 16,837
Preferred Stock of Subsidiary With Mandatory Redemption Provisions 194 137
Utility Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures 300 300
Stockholders' Equity
Preferred stock of subsidiary without mandatory redemption provisions
Nonredeemable 145 145
Redeemable 183 257
Common stock 5,819 6,366
Reinvested earnings 1,992 2,531
-------- --------
Total stockholders' equity 8,139 9,299
Commitments and Contingencies (Notes 2 and 4) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 29,336 $ 30,557
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PG&E CORPORATION
STATEMENT OF CASH FLOWS
(in millions)
For the three months ended March 31, 1998 1997
---------- ----------
Cash Flows From Operating Activities
Net income $ 139 $ 173
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning, and amortization 587 493
Deferred income taxes and tax credits-net (105) (44)
Other deferred charges and noncurrent liabilities (304) 29
Net effect of changes in operating assets
and liabilities:
Accounts receivable 19 107
Regulatory balancing accounts receivable 296 (52)
Inventories 78 27
Accounts payable 20 (34)
Accrued taxes 257 220
Other working capital (147) 9
Other-net 12 41
--------- ---------
Net cash provided by operating activities 852 969
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (506) (328)
Investments in unregulated projects (7) (31)
Acquisitions - (41)
Other-net (3) (16)
--------- ---------
Net cash used by investing activities (516) (416)
--------- ---------
Cash Flows From Financing Activities
Net increase (decrease) in short-term borrowings 32 122
Long-term debt issued 158 -
Long-term debt matured, redeemed, or repurchased-net (400) (257)
Preferred stock redeemed or repurchased (7) -
Common stock issued 17 14
Common stock repurchased (1,122) (320)
Dividends paid (134) (131)
Other-net (14) (4)
--------- ---------
Net cash used by financing activities (1,470) (576)
--------- ---------
Net Change in Cash and Cash Equivalents (1,134) (23)
Cash and Cash Equivalents at January 1 1,397 144
--------- ---------
Cash and Cash Equivalents at March 31 $ 263 $ 121
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 141 $ 67
Income taxes 1 26
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(in millions)
Three months ended March 31,
1998 1997
--------- ---------
Electric utility $ 1,562 $ 1,722
Gas utility 463 552
-------- --------
Total operating revenues 2,025 2,274
Operating Expenses
Cost of electric energy 488 510
Cost of gas 178 215
Operating and maintenance, net 726 661
Depreciation and decommissioning 529 443
Provision for regulatory adjustment mechanisms (322) -
-------- --------
Total operating expenses 1,599 1,829
-------- --------
Operating Income 426 445
Interest expense, net 131 136
Other income and expense (4) (1)
-------- --------
Income Before Income Taxes 299 310
Income taxes 144 138
-------- --------
Net Income 155 172
Preferred dividend requirement and
redemption premium 7 8
-------- --------
Income Available for Common Stock $ 148 $ 164
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEET (in millions)
Balance at
March 31, December 31,
1998 1997
------------ ------------
ASSETS
Current Assets
Cash and cash equivalents $ 89 $ 80
Short-term investments 24 1,143
Accounts receivable
Customers, net 1,066 1,204
Regulatory balancing accounts 782 658
Related parties accounts receivable 851 459
Inventories and prepayments 475 523
--------- ---------
Total current assets 3,287 4,067
Property, Plant, and Equipment
Electric 26,330 26,033
Gas 6,964 6,939
--------- ---------
Total property, plant, and equipment (at original cost) 33,294 32,972
Accumulated depreciation and decommissioning (16,129) (15,558)
--------- ---------
Net property, plant, and equipment 17,165 17,414
Other Noncurrent Assets
Regulatory assets 2,177 2,283
Nuclear decommissioning funds 1,074 1,024
Other 351 359
-------- --------
Total noncurrent assets 3,602 3,666
-------- --------
TOTAL ASSETS $ 24,054 $ 25,147
======== ========
LIABILITIES AND EQUITY
Current Liabilities
Current portion of long-term debt $ 503 $ 580
Current portion of rate reduction bonds 106 125
Accounts payable
Trade creditors 440 441
Related parties 125 134
Other 426 424
Accrued taxes 506 229
Deferred income taxes 32 149
Other 472 527
-------- -------
Total current liabilities 2,610 2,609
Noncurrent Liabilities
Long-term debt 5,945 6,218
Rate reduction bonds 2,776 2,776
Deferred income taxes 3,333 3,304
Deferred tax credits 327 338
Other 1,791 1,810
-------- -------
Total noncurrent liabilities 14,172 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 183 257
Common stock 4,132 4,582
Reinvested earnings 2,375 2,671
-------- --------
Total stockholders' equity 6,835 7,655
Commitments and Contingencies (Notes 2 and 4) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 24,054 $ 25,147
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(in millions)
For the three months ended March 31, 1998 1997
----------- -----------
Cash Flows From Operating Activities
Net income $ 155 $ 173
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning, and amortization 557 476
Deferred income taxes and tax credits-net (114) (62)
Other deferred charges and noncurrent liabilities 18 55
Provision for regulatory adjustment mechanisms (322) -
Net effect of changes in operating assets
and liabilities:
Accounts receivable (255) 68
Regulatory balancing accounts receivable 296 (52)
Inventories 42 28
Accounts payable 18 (145)
Accrued taxes 272 218
Other working capital (61) (16)
Other-net 7 7
--------- ---------
Net cash provided by operating activities 613 750
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (331) (321)
Other-net (9) (98)
--------- ---------
Net cash used by investing activities (340) (419)
--------- ---------
Cash Flows From Financing Activities
Net increase (decrease) in short-term borrowings - (74)
Long-term debt matured, redeemed, or repurchased-net (389) (223)
Preferred stock redeemed or repurchased (65) -
Common stock repurchased (800) -
Dividends paid (123) (131)
Other-net (6) (6)
--------- ---------
Net cash used by financing activities (1,383) (434)
--------- ---------
Net Change in Cash and Cash Equivalents (1,110) (103)
Cash and Cash Equivalents at January 1 1,223 144
--------- ---------
Cash and Cash Equivalents at March 31 $ 113 $ 41
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 96 $ 65
Income taxes - 26
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: GENERAL
Basis of Presentation:
- ----------------------
This Quarterly Report on 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 on Form 10-K.
PG&E Corporation believes that the accompanying statements reflect all
adjustments that are 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 August 1997, the Corporation announced that its subsidiary, U.S.
Generating Company (USGen), had agreed to buy a portfolio of electric
generating assets and power supply contracts from the New England Electric
System (NEES) for $1.59 billion, plus $85 million for early retirement and
severance costs previously committed to by NEES. Including fuel and other
inventories and transaction costs, financing requirements are expected to
total approximately $1.75 billion, of which approximately $1.25 billion will
be funded through debt borrowed by USGen. In addition, approximately $500
million of equity will be contributed. The assets to be acquired contain a
balance of hydro, coal, oil, and natural gas generation facilities. The
acquisition is expected to be completed in the second half of 1998. The
acquisition is subject to regulatory approvals.
In addition, as discussed below in Generation Divestiture, as part of
electric industry restructuring, the Utility has informed the California
Public Utilities Commission (CPUC) that it does not intend to retain any of
its non-nuclear generation facilities.
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. Hedge
transactions are accounted for under the deferral method with gains and
losses on these transactions initially deferred and classified as
inventories and prepayments and other liabilities in the Consolidated
Balance Sheet and then recognized in cost of energy commodities and services
when the hedged transaction occurs.
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 fossil-
fueled generation plants are divested. (See 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.
As stated above, the Corporation utilizes the mark-to-market method of
accounting for its non-hedging commodity trading and price risk management
activities. In accordance with the mark-to-market method of accounting, the
Corporation's electric power, natural gas and related non-hedging contracts,
including both physical and financial instruments, are recorded at market
value, net of future servicing costs and reserves, and recognized in the
income statement as revenue or expense in the period of contract execution.
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. The
resultant 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 quarter ended March 31, 1998, were not
material.
NOTE 2: The Electric Business
On March 31, 1998, California became one of the first states in the country
to allow open competition in the electric generation business. 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.
There are three principal elements to this transition plan: (1) an
electric rate freeze and rate reduction, (2) recovery of transition costs,
and (3) economic divestiture of Utility-owned generation facilities. Each
one of these three elements, and the impact of the transition plan on the
Utility's customers are discussed below. The transition plan will remain in
effect until the earlier of March 31, 2002, or when the Utility has
recovered its authorized transition costs as determined by the CPUC. This
period is referred to as the transition period. 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 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. During the first quarter
of 1998, the electric rate reduction reduced operating revenue by
approximately $94 million.
To pay for the 10 percent rate reduction, the Utility financed $2.9
billion of its transition costs with rate reduction bonds. The bonds defer
recovery of a portion of the transition costs until after the transition
period. The transition costs associated with the rate reduction bonds are
expected to be recovered over the term of the bonds.
Transition Cost Recovery:
- ------------------------
The second element of the transition plan is recovery of transition costs.
Transition costs are costs which are unavoidable and which are 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.
(In general, regulatory assets are expenses deferred in the current or prior
periods to be included in rates in subsequent periods.)
The costs of Utility-owned generation facilities are currently included
in the Utility customers' rates. Above-market facility costs are those
facilities whose values recorded on the Utility's balance sheet (book value)
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. In general, 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 the
Utility's generation facilities. This market valuation process is expected
to occur prior to the conclusion of the transition period. The first of
these valuations occurred in 1997 when the Utility agreed to sell three
Utility-owned electric generation plants for $501 million. The sale is
scheduled to close during 1998. (See Generation Divestiture, below.) At
March 31, 1998, the Utility's net investment in Diablo Canyon Nuclear Power
Plant (Diablo Canyon) and non-nuclear generation facilities was $3.5 billion
and $2.6 billion, respectively, including the plants to be sold in 1998.
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 360 million megawatt-hours at
an aggregate average price of 6.3 cents per kilowatt-hour. To the extent
that this price is above the market price, the Utility is authorized 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 March 31, 1998, the
Utility has accumulated approximately $1.8 billion of these assets net of
obligations.
Under the transition plan, 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, in accordance with the transition plan, the Utility is
recording depreciation of certain generating plants determined to be
uneconomic in proceedings before the CPUC and 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 is 6.77 percent.
Although most transition costs must be recovered by March 31, 2002,
certain transition costs can 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. 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, this charge 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 CPUC has the ultimate authority to determine the recoverable amount of
transition costs. Reviews by the CPUC to determine the reasonableness of
transition costs are being conducted and will continue to be conducted
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 accounts include sunk costs at December
31, 1996 of $3.3 billion which reflects total construction costs of $7.1
billion. (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, following the completion of the
audit. Transition costs that are 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 is collecting eligible transition
costs through a CPUC-authorized nonbypassable charge. The amount of revenue
collected for transition costs recovery is subject to seasonal fluctuations
in the Utility's sales volumes. The first quarter amortization and
depreciation of transition costs exceeded revenue associated with transition
costs recovery by $322 million. In accordance with CPUC rate treatment of
transition costs, the Utility deferred this excess.
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. Given the Utility's
current evaluation of these factors, the Utility believes that it will
recover its transition costs. Also, the Utility believes that its
regulatory assets and Utility-owned generation facilities are not impaired.
However, a change in one or more of these factors could affect the
probability of recovery of transition costs and result in a material charge.
Generation Divestiture:
- -----------------------
The third element of the transition plan is the economic divestiture of
Utility-owned generation facilities. To alleviate market power concerns of
the CPUC, the Utility has agreed to sell its fossil-fueled generation
facilities.
In 1997, the Utility agreed to sell three electric Utility-owned fossil-
fueled generating plants to Duke Energy Power Services Inc. (Duke) through a
competitive auction process. The aggregate bid accepted for these plants
was $501 million. These three fossil-fueled plants have a combined book
value at March 31, 1998, of approximately $370 million and a combined
capacity of 2,645 megawatts (MW). The three power plants are located at
Morro Bay, Moss Landing, and Oakland.
The sales have been approved by the CPUC. However, they are still
subject to various regulatory approvals including the approval of the
transfer of various permits and licenses, and the Federal Energy Regulatory
Commission's acceptance for filing of Duke's requested regulatory treatment.
Additionally, the Utility will retain 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. The sale of
these three plants is scheduled to close in 1998.
The Utility began an auction of four of its remaining fossil-fueled
plants and its geothermal facilities in April 1998. These additional plants
have a combined generating capacity of 4,718 MW and a combined book value at
March 31, 1998, of approximately $720 million.
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 Corporation has also informed the CPUC that it does not intend to
retain the Utility's remaining 2,672 MW of fossil-fueled and hydroelectric
facilities as part of the Utility. These remaining facilities have a
combined book value at March 31, 1998, of approximately $1.7 billion. The
Utility expects to announce a plan for disposition of these facilities by
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.
Voter Initiative:
- -----------------
Various consumer groups filed a voter initiative with the California
Attorney General which would (1) require the Utility to provide an
additional 10 percent rate reduction to its residential and small commercial
customers; (2) eliminate transition cost recovery for nuclear investments
(other than reasonable decommissioning costs); (3) restrict transition cost
recovery for non-nuclear investments (other than costs associated with QFs),
unless the CPUC finds that the Utility would be deprived of the opportunity
to earn a fair rate of return; and (4) prohibit the collection of any
customer charges for rate reduction bonds, or alternatively, require the
Utility to offset such charges with an equal credit to customers. If the
sponsors of the initiative obtain sufficient signatures to qualify the
initiative for the November 1998, statewide ballot, and if the initiative
were voted into law, a material charge would result to the extent that
regulated rates would no longer be adequate to recover transition costs. In
this event, we expect that legal challenges by the Utility and others would
ensue.
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, 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. An additional $8.7
billion of coverage is provided by secondary financial protection which is
mandated by federal legislation and 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, 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.
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 to be
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 March 31, 1998, of
$246 million for hazardous waste remediation costs at identified sites,
including fossil-fueled power plants. Environmental remediation at
identified sites may be as much as $420 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. This upper limit of the range of costs was estimated 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 identifiable
possible outcomes change.
Of the $246 million liability, discussed above, the Utility has recovered
$68 million and expects to recover $153 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 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 March 31, 1998, the Utility's net investment was $688 million.
This net investment is comprised of the pumped storage facility (including
regulatory assets of $48 million), common plant, and dedicated transmission
plant. 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, the uneconomic, above-market
portion of Helms is 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 rate recovery. 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.
The Corporation has also informed the CPUC that it does not intend to
retain Helms as part of the Utility. See 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 has 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 has replaced the shares sold to
the Corporation through purchases on the open market or through privately
negotiated transactions. The contract is anticipated to expire by December
31, 1998. This additional obligation may be settled in either shares of
stock or cash and is not expected to have a material impact on the
Corporation's financial position or results of operations.
Legal Matters:
- --------------
Chromium Litigation:
In 1994 through 1997, several civil suits were filed against the Utility on
behalf of approximately 3,000 individuals. During the first quarter of
1998, claims on behalf of 240 of these individuals were dismissed, subject
to possible appeal. 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.
The Utility is responding to the suits and asserting affirmative
defenses. The Utility will pursue appropriate legal defenses, including
statute of limitations or exclusivity of workers' compensation laws, and
factual defenses including lack of exposure to chromium and the inability of
chromium to cause certain of the illnesses alleged.
The Corporation believes that the ultimate outcome of this matter will
not have a material impact on its or the Utility's financial position or
results of operations.
Texas Franchise Fee Litigation:
In connection with PG&E Corporation's acquisition of Valero Energy
Corporation in July 1997, now known as PG&E Gas Transmission, Texas
Corporation (GTT), GTT succeeded to the litigation described below.
GTT and various of its affiliates are defendants in at least two class
action suits and six separate suits filed by various Texas cities. The
class action suits involve plaintiffs that serve as class representatives
for classes consisting of every municipality in Texas (excluding certain
cities which filed separate suits) in which any of the defendants engaged in
business activities related to natural gas or natural gas liquids or sold or
supplied gas or used public rights-of-way. Generally, these cities allege,
among other things, that (1) the defendants that own or operate pipelines
have occupied city property and conducted pipeline operations without the
cities' consent and without compensating the cities, and (2) the defendants
that are gas marketers have 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 on 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) 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). Our Utility's consolidated financial
statements include its accounts as well as those of its wholly owned and
controlled subsidiaries. This MD&A should be read in conjunction with the
consolidated financial statements included herein. Further, this quarterly
report should be read in conjunction with the Corporation's and the
Utility's Consolidated Financial Statements and Notes to Consolidated
Financial Statements incorporated by reference in their combined 1997 Annual
Report on Form 10-K.
In this MD&A, we explain the results of operations for the three months
ended March 31, 1998, as compared to the corresponding period in 1997 and
discuss our financial condition. Our discussion of financial condition
includes:
- - changes in the energy industry and how we expect these changes to
influence future results of operations,
- - liquidity and capital resources, including discussions of capital
financing activities, and uncertainties that could affect future results,
and
- - risk management activities.
This Quarterly Report on Form 10-Q, including our discussion of results
of operations and financial condition below, contains forward-looking
statements that involve risks and uncertainties. Words such as "estimates,"
"expects," "anticipates," "plans," "believes," and similar expressions
identify forward-looking statements involving risks and uncertainties.
These risks and uncertainties include, but are not limited to, the
ongoing restructuring of the electric and gas industries in California and
nationally, the continued application of the regulatory framework
established by the California Public Utilities Commission (CPUC) and state
legislation, the outcome of the regulatory proceedings related to those
restructurings, our Utility's ability to collect revenues sufficient to
recover transition costs in accordance with its transition cost recovery
plan, the planned sale of the electric Utility-owned fossil-fueled
generating plants and the retention of the environmental remediation
liability for these plants, as discussed in the Competition and the Changing
Regulatory Environment section below. Risks and uncertainties also include
the impact of our planned acquisition as discussed in the Acquisitions and
Sales section below, the approval of our Utility's 1999 General Rate Case
application resulting in the Utility's ability to earn its authorized rate
of return as discussed in the Liquidity and Capital Resources section below,
and our ability to successfully compete outside our traditional regulated
markets. The ultimate impacts on future results of increased competition,
the changing regulatory environment, our expansion into new businesses and
markets, and the CPUC decision on the 1999 General Rate Case application are
uncertain, but all are expected to fundamentally change how we conduct our
business. The outcome of these changes and other matters discussed below
may cause future results to differ materially from historic results, or from
results or outcomes currently expected or sought by PG&E Corporation.
RESULTS OF OPERATIONS
In this section, we provide the components of our earnings for the three
months ended March 31, 1998 and 1997. We then explain why operating
revenues and expenses for 1998 and 1997 were different between the years.
The following table shows our results of operations for the three months
ended March 31, 1998 and 1997, and total assets at March 31, 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.
(in millions)
Unregulated Corporate
Business and
Utility Operations Other Total
-------- ------------ --------- -------
For the three months ended
March 31,
1998
Operating revenues $ 2,025 $ 2,341 $ (13) $ 4,353
Operating expenses 1,599 2,302 (13) 3,888
------- ------- ------ -------
Operating income
before income taxes 426 39 - 465
Income available for
common stock 148 6 (15) 139
Total assets at March 31 $24,054 $ 6,555 $(1,273) $29,336
1997
Operating revenues $ 2,274 $ 1,104 $ (13) $ 3,365
Operating expenses 1,829 1,085 (13) 2,901
------- ------- ------- -------
Operating income
before income taxes 445 19 - 464
Income available for
common stock 164 11 (2) 173
Total assets at March 31 $23,456 $ 3,357 $ (176) $26,637
Common Stock Dividend:
- ----------------------
Our common stock dividend is based 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 set a number of conditions when PG&E Corporation was formed as a
holding company. One of these conditions requires our Utility to maintain,
on average, its CPUC-authorized capital structure, potentially limiting the
amount of dividends our Utility may pay PG&E Corporation. At March 31,
1998, our Utility was in compliance with its CPUC-authorized capital
structure. We believe that our Utility will continue to meet this condition
in the future without affecting our ability to pay common stock dividends to
common shareholders.
Earnings Per Common Share:
- --------------------------
Earnings per common share for the three months ended March 31, 1998,
decreased $.06 as compared to the same period in 1997. Earnings per common
share were affected by the activity discussed below.
Utility Results:
- ----------------
Our Utility operating revenues for the three month period ended March 31,
1998, decreased $249 million as compared to the same period in 1997.
Operating revenues declined because of the 10 percent electric rate
reduction provided to residential and small commercial customers and due to
changes in regulatory adjustment mechanisms resulting from electric industry
restructuring. During the first quarter of 1998, the electric rate
reduction decreased operating revenues by approximately $94 million.
Electric rates for all our other customers have been held at 1996 levels.
In connection with electric industry restructuring, our volumetric (ERAM)
and energy cost (ECAC) revenue balancing accounts were terminated.
Balancing account revenues related to ERAM and ECAC totaled approximately
$166 million in the three month period ended March 31, 1997. The ERAM and
ECAC balancing accounts have been replaced with regulatory adjustment
mechanisms which impact expenses instead of revenues as discussed in
Transition Cost Recovery, below.
Utility operating expenses decreased $230 million for the three month
period ended March 31, 1998, as compared to the same period in 1997.
Operating expenses declined primarily as a result of lower gas prices and
expense deferrals related to electric industry restructuring, which were
partially offset by system reliability, storm response costs, and costs
associated with a refueling and maintenance outage at Diablo Canyon Nuclear
Power Plant (Diablo Canyon) from February 14, 1998 through March 28, 1998.
As previously indicated, electric industry restructuring provides for
recovery of certain costs in future periods. Some costs 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.
Utility operations contributed $16 million less to net income in the
three month period ended March 31, 1998, than in the same period in 1997
primarily due to the lower authorized rate of return on equity of 6.77
percent applicable to all of our Utility-owned electric generation-related
assets.
Unregulated Business Results:
- -----------------------------
Our unregulated business operations includes those business activities that
are not directly regulated by the CPUC. Unregulated business operating
revenues for the three month period ended March 31, 1998, increased $1.2
billion while operating expenses also increased $1.2 billion as compared to
the same period in 1997, due to the acquisitions of Teco Pipeline Company in
January 1997 and the natural gas operations of Valero Energy Corporation in
July 1997, and due to operations associated with our energy commodities and
services activities. Unregulated business operations contributed $5 million
less in net income in the three month period ended March 31, 1998, than was
contributed in the same period in 1997, primarily due to start up costs
associated with the energy service business, which was partially offset by
income generated from independent power projects managed by USGen.
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:
Energy Industry:
The Electric 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,
Californians can choose who provides 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.
To create this 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
oversees California's electric transmission grid making sure 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 schedules the delivery
or 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. 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 our Utility to purchase all electric power for
its retail customers from the PX or from must-take resources. And,
excluding must-take resources, we must sell all of our Utility-generated
electric power to the PX. In future periods, the Cost of Energy for
Utility, reflected on the Statement of Consolidated Income, will be
comprised of the cost of PX purchases and the cost of Utility generation net
of sales to the PX.
Generation revenues currently make up approximately 30 percent of our
total Utility revenues. After the transition period, discussed below,
generation revenues will be determined principally by an open electric
commodity market. 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. And, we have made strategic investments throughout the
nation that will further position us as a national energy provider. The
following sections discuss the transition plan.
Electric Transition Plan:
- -------------------------
In developing state legislation to implement a competitive market, it was
anticipated 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.
There are three principal elements to this transition plan: (1) an
electric rate freeze and rate reduction, (2) recovery of transition costs,
and (3) economic divestiture of Utility-owned generation facilities. Each
one of these three elements, and the impact of the transition plan on our
Utility's customers are discussed below. The transition plan will remain in
effect until the earlier of March 31, 2002, or when we have recovered our
authorized transition costs as determined by the CPUC. This period is
referred to as the transition period. 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.
Rate Freeze and Rate Reduction:
- -------------------------------
The first element of the transition plan 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. During the first
quarter of 1998, the rate reduction reduced operating revenue by
approximately $94 million.
To pay for the 10 percent rate reduction, we financed $2.9 billion of our
transition costs with rate reduction bonds. The bonds defer recovery of a
portion of the transition costs until after the transition period. The
transition costs associated with the rate reduction bonds are expected to be
recovered over the term of the bonds.
Transition Cost Recovery:
- -------------------------
The second element of the transition plan is recovery of transition costs.
Transition costs are costs which are unavoidable and which are 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. (In general, regulatory assets
are expenses deferred in the current or prior periods to be included in
rates in subsequent periods.)
The costs of Utility-owned generation facilities are currently included
in our Utility customers' rates. Above-market facility costs are those
facilities whose values recorded on our balance sheet (book value) 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. In general, 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.
We 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. This market valuation process is expected to occur
prior to the conclusion of the transition period. The first of these
valuations occurred in 1997 when we agreed to sell three Utility-owned
electric generation plants for $501 million. The sale is scheduled to close
during 1998 (See Generation Divestiture, below). At March 31, 1998, our
Utility's net investment in Diablo Canyon and Utility-owned non-nuclear
generation facilities was $3.5 billion and $2.6 billion, respectively,
including the plants to be sold in 1998.
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
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 360 million megawatt-hours at
an aggregate average price of 6.3 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 March 31, 1998, we have
accumulated approximately $1.8 billion of these assets net of obligations.
Under the transition plan, 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, in accordance with the transition plan, the Utility is
recording depreciation of certain generating plants determined to be
uneconomic in proceedings before the CPUC and 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 is 6.77 percent.
Although most transition costs must be recovered by March 31, 2002,
certain transition costs can 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. 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, this charge 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 CPUC has the ultimate authority to determine the recoverable amount
transition costs. Reviews by the CPUC to determine the reasonableness of
transition costs are being conducted and will continue to be conducted
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 accounts include sunk costs at December
31, 1996 of $3.3 billion which reflects total construction costs of $7.1
billion. (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, following the completion of the
audit. Transition costs that are 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 is collecting eligible transition
costs through a CPUC-authorized nonbypassable charge. The amount of revenue
collected for transition costs recovery is subject to seasonal fluctuations
in the Utility's sales volumes. The first quarter amortization and
depreciation of transition costs exceeded revenue associated with transition
costs recovery by $322 million. In accordance with CPUC rate treatment of
transition costs, the Utility deferred this excess.
Our 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. Given our current
evaluation of these factors, we believe that we will recover our transition
costs. Also, we believe that our regulatory assets and Utility-owned
generation facilities are not impaired. However, a change in one or more of
these factors could affect the probability of recovery of transition costs
and result in a material charge.
Generation Divestiture:
- -----------------------
The third element of the transition plan is the economic divestiture of
Utility-owned generation facilities. To alleviate market power concerns of
the CPUC, we have agreed to sell our fossil-fueled generation facilities.
In 1997, we agreed to sell three electric Utility-owned fossil-fueled
generating plants to Duke Energy Power Services, Inc. (Duke) through a
competitive auction process. The aggregate bid accepted for these plants
was $501 million. These three fossil-fueled plants have a combined book
value at March 31, 1998, of approximately $370 million and a combined
capacity of 2,645 megawatts (MW). The three power plants are located at
Morro Bay, Moss Landing, and Oakland.
The sales have been approved by the CPUC. However, they are still
subject to various regulatory approvals, including the approval of the
transfer of various permits and licenses, and Federal Energy Regulatory
Commission's (FERC) acceptance for filing of Duke's requested regulatory
treatment. Additionally, the Utility will retain liability for required
environmental remediation of any pre-closing soil or groundwater
contamination at these plants. Although we are retaining such environmental
remediation liability, we do not expect any material impact on the Utility's
or our financial position or results of operations. The sale of these three
plants is scheduled to close in 1998.
We began an auction of four of our remaining Utility-owned fossil-fueled
plants and our Utility-owned geothermal facilities in April 1998. These
additional plants have a combined generating capacity of 4,718 MW and a
combined book value at March 31, 1998, of approximately $720 million.
We have also informed the CPUC that we do not intend to retain our
remaining 2,672 MW of Utility-owned fossil-fueled and hydroelectric
facilities as part of the Utility. These remaining facilities have a
combined book value at March 31, 1998, of approximately $1.7 billion. Our
Utility expects to announce a plan for the disposition of the facilities by
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.
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. However, a material charge
may occur if the fair values of generation facilities, which are disposed by
the Utility but retained by the Corporation, are determined to be in excess
of the facilities' book values. This is because the excess would be used to
reduce other transition costs without being collected in rates.
Customer Impacts of Transition Plan:
- ------------------------------------
Effective March 31, 1998, all Californians may choose their electric
commodity provider. As of March 31, 1998, our Utility had accepted
approximately 30,000 requests to switch their electric commodity supplier
from the Utility to another electric commodity provider.
Regardless of the customer's choice of electric commodity provider,
during the transition period, 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 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 can 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 reduce the
customer's bill by the savings. The electric provider 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.
Voter Initiative:
- -----------------
Various consumer groups filed a voter initiative with the California
Attorney General which would (1) require the Utility to provide an
additional 10 percent rate reduction to its residential and small commercial
customers; (2) eliminate transition cost recovery for nuclear investments
(other than reasonable decommissioning costs); (3) restrict transition cost
recovery for non-nuclear investments (other than costs associated with QFs),
unless the CPUC finds that the Utility would be deprived of the opportunity
to earn a fair rate of return; and (4) prohibit the collection of any
customer charges for rate reduction bonds, or alternatively, require the
Utility to offset such charges with an equal credit to customers. If the
sponsors of the initiative obtain sufficient signatures to qualify the
initiative for the November 1998, statewide ballot, and if the initiative
were voted into law, a material charge would result to the extent that
regulated rates would no longer be adequate to recover transition costs. In
this event, we expect that legal challenges by the Utility and others would
ensue.
The Gas Business:
In March 1998, our Utility implemented the Gas Accord Settlement (Accord).
The Accord is an agreement with a broad coalition of customer groups and
industry participants that has restructured our Utility's natural gas
business. Upon implementation, our Utility's gas business experienced five
key changes:
1. The Accord separated (or unbundled) our Utility's gas transmission
and storage services from its distribution services.
2. The Accord increased the opportunity for our Utility's residential
and small commercial (core)customers to purchase gas from competing
suppliers.
3. The Accord established a new method, based on market indices, to
measure the reasonableness of our Utility's gas purchases to serve its core
customers.
4. The Accord established gas transmission and storage rates for the
period from March 1998 through December 2002.
5. The Accord eliminated regulatory protection for transmission revenues
from our Utility's industrial and large commercial (noncore) customers.
As a result, we are subject to an increased risk for variations in revenues
arising from fluctuations in noncore transmission throughput. These
differences were previously deferred in balancing accounts. We do not
however expect these variations to have a material impact on the Utility's
or the Corporation's financial position or results of operations.
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 various new
alternative market structures with the goal of encouraging competition and
customer choice, while maintaining a high standard of consumer protection.
At this point, we cannot predict the outcome of these proceedings and their
impact on our financial position and results of operations.
ACQUISITIONS AND SALES:
In 1997, PG&E Corporation announced that it had agreed to acquire, through
its subsidiary 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
previously committed to by NEES. Including fuel and other inventories and
transaction costs, financing requirements are expected to total
approximately $1.75 billion, of which approximately $1.25 billion will be
funded through debt borrowed by USGen. In addition, approximately $500
million of equity will be contributed. The assets contain a balance of
hydro, coal, oil, and natural gas generation facilities. The acquisition is
subject to regulatory approvals. The acquisition is expected to be
completed in the second half of 1998.
In addition, as discussed above in Generation Divestiture, as part of
electric industry restructuring, our Utility has informed the CPUC that it
does not intend to retain any of its non-nuclear generation facilities.
YEAR 2000 COMPLIANCE
In 1995, we began and presently continue to review and assess our computer
and information systems in anticipation of Year 2000 issues. 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.
PG&E Corporation expects to complete critical software modifications by
the end of 1998 and to complete validation of these systems in 1999. We
are compiling an inventory of all systems with embedded electronic
components and assessing the degree of Year 2000 compliance. During 1999,
we also expect to have completed validation of all critical vendor-supplied
embedded electronic systems or replacement of those systems found not to be
Year 2000 compliant.
Our various lines of business are also dependent upon external parties
including customers, suppliers, business partners, government agencies, and
financial institutions for the reliable delivery of our products and
services. To the extent that any of these parties experience Year 2000
problems in their systems, our service reliability may be adversely
affected. We plan to assess the degree to which each of these external
parties has adequate plans to address Year 2000 problems in its systems. If
judged necessary and if possible, we will develop contingency plans to
reduce the risk of material impacts on our operations through external Year
2000 problems.
We believe our plans of action are adequate to secure Year 2000
compliance of our critical systems and to reduce the risk of external
impacts to our operations. Therefore, we do not currently anticipate any
material impact on the Utility's or PG&E Corporation's financial position or
results of operations as a result of the Year 2000 issue. Nevertheless,
achieving Year 2000 compliance is subject to the risks and uncertainties
described above. If our internal systems, or the internal systems of
external parties, fail to achieve Year 2000 compliance, business or results
of operations of the Utility or PG&E Corporation could be adversely
affected.
LIQUIDITY AND CAPITAL RESOURCES:
Sources of Capital:
- ------------------
The Corporation's capital requirements are funded 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 three months ended March 31, 1998, PG&E Corporation issued
$18 million of common stock, generally through the Dividend Reinvestment
Plan and the Stock Option Plan. Also during the three months ended March
31, 1998, PG&E Corporation paid dividends of $126 million and declared
dividends of $114 million. The Utility paid dividends of $115 million and
declared dividends of $100 million to PG&E Corporation during the three
months ended March 31, 1998. The Utility began a program of buying back
its stock from PG&E Corporation in the first quarter of 1998.
As of December 31, 1997, the Board of Directors had authorized us to
repurchase up to $1.7 billion of our common stock on the open market or in
negotiated transactions. As part of this authorization, in January 1998,
the Corporation repurchased in a specific transaction 37 million shares of
common stock at $30.3125 per share. In connection with this transaction,
the Corporation has 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 has replaced the shares sold to the Corporation
through purchases on the open market or through privately negotiated
transactions. The contract is anticipated to expire by December 31, 1998.
This additional obligation may be settled in either shares of stock or cash
and is not expected to have a material impact on the Corporation's 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. Both of these credit facilities are to be used for general
corporate purposes. There were no borrowings under the credit facilities at
March 31, 1998.
At March 31, 1998, the Corporation, primarily through an unregulated
business subsidiary, had $135 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 April 1998, the Utility repurchased $800 million of its common stock
from PG&E Corporation with 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
three months ended March 31, 1998, amounted to $357 million. Of this
amount, $249 million related to the Utility's redemption of its 8 percent
mortgage bonds due October 1, 2025, and $94 million related to Utility's
repurchase of its other mortgage bonds. The remaining $14 million related
primarily to the scheduled maturity of long-term debt.
In January 1998, the Utility redeemed its Series 7.44 percent preferred
stock with a face value of $65 million.
The Utility maintains a $1 billion revolving credit facility which
expires in 2002. The facility may be extended annually for additional one-
year periods upon mutual agreement between the Utility and the banks. There
were no borrowings under this credit facility at March 31, 1998.
The table below provides information on PG&E Corporation's debt
obligations at March 31, 1998:
Expected Maturity Date 1998 1999 2000 2001 2002 Thereafter Total(1)
- ---------------------- ---- ---- ---- ---- ---- ---------- -------
Long-term debt
Fixed rate $566 $294 $460 $330 $515 $4,597 $6,762
Average interest rate 5.8% 6.3% 6.0% 7.8% 7.7% 7.2% 6.9%
Variable rate - - - - - $1,348 $1,348
Rate reduction bonds $106 $265 $280 $300 $290 $1,641 $2,882
Average interest rate 5.9% 6.0% 6.2% 6.2% 6.3% 6.4% 6.3%
(1) The fair value of the long-term debt and rate reduction bonds is the
same as the book value.
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 Cost of Capital Application with the
CPUC. The filing requests 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. A final CPUC decision is
expected in December 1998, to be effective January 1, 1999.
The Utility did not request a 1999 rate of return for its gas transmission,
storage, or gas gathering operations because the CPUC has approved the Gas
Accord which sets the rates and revenue requirements for these lines of
business until 2002. Also, no request was included for electric transmission
operations since under direct access the transmission network is regulated by
the FERC.
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
will file a separate application if the rehearing request is granted.
1999 General Rate Case (GRC):
- -----------------------------
In December 1997, we filed our 1999 GRC application with the CPUC. During
the GRC process, the CPUC examines our Utility's non-fuel related costs to
determine the amount we can charge customers. In our application, we
requested an increase in our Utility's authorized revenues, effective
January 1, 1999. The requested increase, as updated in April 1998, consists
of an increase of $572 million in electric utility revenues and an increase
of $460 million in gas utility revenues over authorized 1998 revenues.
In April 1998, a CPUC commissioner issued a ruling which delays the
projected date for a final CPUC decision in the GRC until January 1999,
with a proposed decision scheduled to be issued in December 1998. This
schedule delays the proceedings by approximately one month compared to
previous expectations. The revised schedule reflects the desire by
intervenor parties, including the CPUC's Office of Ratepayer Advocates, for
more time to prepare analysis and testimony. To accommodate the
delayed schedule, the ruling permits us to submit a plan for establishing
interim rates, effective on January 1, 1999, to cover the period between
that date and the date a final CPUC decision is issued. A decision on
interim rates is scheduled to be issued in November 1998.
The 1999 GRC will not affect the authorized revenues for electric and gas
transmission services or for gas storage services. The authorized revenues
for each of these services are determined in other proceedings.
Utility electric transmission revenues are authorized by the FERC. In
March 1998, we filed an application with the FERC requesting 1998 Utility
electric retail transmission revenues of $331 million. The requested
revenue is consistent with Utility electric transmission revenues in CPUC-
authorized 1997 electric rates. In the application, we requested to place
the new rates in effect, subject to refund, on March 31, 1998, consistent
with the ISO and PX operational date. The new rates will supersede the
previously requested revenues of $305 million currently in effect, subject
to refund.
Also, revenues associated with gas transmission and storage services
were authorized as part of the Gas Accord. See the Gas Business section,
above, for a discussion of the Gas Accord.
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 March 31, 1998, the Utility expects to spend $246 million for clean-up
costs at identified sites over the next 30 years. If other responsible
parties fail to pay or identified outcomes change, then these costs may be
as much as $420 million. Of the $246 million, the Utility has recovered $68
million and expects to recover $153 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. Substantially all of
these have been litigated or settled with no material impact on the
Utility's or the Corporation's results of operations or financial position.
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 fossil-fueled generation plants are divested (See
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.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information concerning PG&E Corporation's and Pacific Gas and Electric
Company's market risk is included in the table providing information about
debt obligations in the above section Sources of Capital, and also in the
above section Risk Management Activities.
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, claims against Pacific Gas and Electric Company on
behalf of approximately 2,800 plaintiffs were pending in eight
civil actions filed in California courts (known collectively as
the "Aguayo Litigation"). Two of these 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. Plaintiffs in both
actions have agreed to dismiss PG&E Corporation as a defendant.
Each of the 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 March 30, 1998, a Los Angeles Superior Court judge dismissed
the claims of 240 plaintiffs in Aguayo v. Pacific Gas and
Electric Company who were neither personally exposed to chromium
nor yet conceived at the time of their parents' alleged exposure.
The judge found that current California law precludes these types
of preconception claims. It is expected that plaintiffs will
appeal this ruling.
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.
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
PG&E Corporation:
On April 15, 1998, PG&E Corporation held its annual meeting of
shareholders. At that meeting, the following matters were voted
as indicated:
1. Election of the following directors to serve until the next
annual meeting of shareholders or until their successors
shall be elected and qualified:
For Withheld
---------- ----------
Richard A. Clarke 277,313,530 6,999,929
Harry M. Conger 278,179,795 6,133,664
David A. Coulter 275,721,980 8,591,479
Lee Cox 278,165,313 6,148,146
William S. Davila 278,194,826 6,118,633
Robert D. Glynn, Jr. 278,236,860 6,076,599
David M. Lawrence, MD 277,866,616 6,446,843
Richard B. Madden 278,145,725 6,167,734
Mary S. Metz 278,089,765 6,223,694
Rebecca Q. Morgan 275,597,117 8,716,342
Carl E. Reichardt 277,990,791 6,322,668
John C. Sawhill 278,166,923 6,146,536
Alan Seelenfreund 278,142,639 6,170,820
Barry Lawson Williams 278,077,940 6,235,519
2. Ratification of the appointment of Arthur Andersen LLP as
independent public accountants for the year 1998:
For: 279,482,833
Against: 2,005,818
Abstain: 2,824,808
The proposal was approved by a majority of the shares present and
voting (including abstentions) which shares voting affirmatively
also constituted a majority of the required quorum.
Each of the shareholder proposals listed below was defeated as
the number of shares voting affirmatively on each proposal
constituted less than a majority of the shares voting and present
(including abstentions) with respect to each proposal.
3. Consideration of a shareholder proposal to appoint
independent directors to key Board committees:
For: 72,457,935
Against: 158,238,439
Abstain: 9,002,693
Broker non-votes:(1) 44,614,392
4. Consideration of a shareholder proposal regarding super
majority voting:
For: 96,676,182
Against: 134,458,016
Abstain: 8,564,869
Broker non-votes:(1) 44,614,392
5. Consideration of a shareholder proposal regarding cumulative
voting:
For: 60,562,835
Against: 165,694,235
Abstain: 13,441,997
Broker non-votes:(1) 44,614,392
- --------------------
(1) A non-vote occurs when a broker or other nominee holding
shares for a beneficial owner votes on one proposal, but does not
vote on another proposal because the broker or other nominee does
not have discretionary voting power and has not received
instructions from the beneficial owner.
6. Consideration of a shareholder proposal regarding director
compensation:
For: 20,512,623
Against: 208,057,428
Abstain: 11,129,016
Broker non-votes:(1) 44,614,392
Pacific Gas and Electric Company:
On April 15, 1998, Pacific Gas and Electric Company held its
annual meeting of shareholders. Shares of capital stock of
Pacific Gas and Electric Company consist of shares of common
stock and shares of first preferred stock. PG&E Corporation, as
owner of all of the 409,120,387 outstanding shares of common
stock, holds approximately 95% of the combined voting power of
the outstanding capital stock of Pacific Gas and Electric
Company. PG&E Corporation voted all of its shares of common
stock for the nominees named in the joint proxy statement, for
the ratification of the appointment of Arthur Andersen LLP as
independent public accountants for the year 1998, and for the
management proposal to decrease the minimum number of directors.
The balance of the votes shown below were cast by holders of
shares of first preferred stock. At the annual meeting, the
following matters were voted as indicated:
1. Election of the following directors to serve until the next
annual meeting of shareholders or until their successors
shall be elected and qualified:
For Withheld
----------- -----------
Richard A. Clarke 423,365,574 269,854
Harry M. Conger 423,368,303 267,125
David A. Coulter 423,366,425 269,003
C. Lee Cox 423,370,269 265,159
William S. Davila 423,372,395 263,033
Robert D. Glynn, Jr. 423,374,990 260,438
David M. Lawrence, MD 423,366,246 269,182
Richard B. Madden 423,370,055 265,373
Mary S. Metz 423,361,953 273,475
Rebecca Q. Morgan 423,358,458 276,970
Carl E. Reichardt 423,362,050 273,378
John C. Sawhill 423,360,841 274,587
Alan Seelenfreund 423,365,942 269,486
Gordon R. Smith 423,374,019 261,409
Barry Lawson Williams 423,362,357 273,071
2. Ratification of the appointment of Arthur Andersen LLP as
independent public accountants for the year 1998:
For: 423,229,793
Against: 138,185
Abstain: 267,450
- --------------------
(1) A non-vote occurs when a broker or other nominee holding
shares for a beneficial owner votes on one proposal, but does not
vote on another proposal because the broker or other nominee does
not have discretionary voting power and has not received
instructions from the beneficial owner.
3. Management proposal regarding decrease in the minimum number
of directors (Item 7 in the joint proxy statement):
For: 423,002,572
Against: 249,621
Abstain: 383,235
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 three months ended March 31, 1998 was 2.66.
Pacific Gas and Electric Company's earnings to combined fixed
charges and preferred stock dividends ratio for the three months
ended March 31, 1998 was 2.50. The statement of the foregoing
ratios, together with the statements of the computation of the
foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are
included herein for the purpose of incorporating such information
and exhibits into Registration Statement Nos. 33-62488, 33-64136,
33-50707 and 33-61959, relating to Pacific Gas and Electric
Company's various classes of debt and first preferred stock
outstanding.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 3.1 Restated Articles of Incorporation of Pacific Gas
and Electric Company effective as of May 6, 1998
Exhibit 3.2 Bylaws of Pacific Gas and Electric Company, dated
May 6, 1998
Exhibit 10.1 PG&E Corporation Director Grantor Trust Agreement
dated April 1, 1998
Exhibit 10.2 PG&E Corporation Officer Grantor Trust Agreement
dated April 1, 1998
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
Exhibit 27.1 Financial Data Schedule for the quarter ended
March 31, 1998 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
March 31, 1998 for Pacific Gas and Electric
Company
(b) Reports on Form 8-K during the first quarter of 1998 and
through the date hereof (2):
1. January 22, 1998 (as amended by Form 8-K/A dated February 5, 1998)
Item 5. Other Events
A. Performance Incentive Plan - Year-to-date Financial
Results
B. 1997 Consolidated Earnings (unaudited)
C. Accelerated Share Repurchase Program
2. April 16, 1998
Item 5. Other Events
A. First Quarter 1998 Consolidated Earnings (unaudited)
B. Pacific Gas and Electric Company's General Rate Case
Proceeding
- --------------------
(2) 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)
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
May 15, 1998 By______________________________
CHRISTOPHER P. JOHNS
Controller
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company)
Exhibit Index
Exhibit No. Description of Exhibit
3.1 Restated Articles of Incorporation of Pacific Gas
and Electric Company effective as of May 6, 1998
3.2 Bylaws of Pacific Gas and Electric Company, dated
May 6, 1998
10.1 PG&E Corporation Director Grantor Trust Agreement
dated April 1, 1998
10.2 PG&E Corporation Officer Grantor Trust Agreement
dated April 1, 1998
11 Computation of Earnings Per Common Share
12.1 Computation of Ratio of Earnings to Fixed Charges
for Pacific Gas and Electric Company
12.2 Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
27.1 Financial Data Schedule for the quarter ended
March 31, 1998 for PG&E Corporation
27.2 Financial Data Schedule for the quarter ended
March 31, 1998 for Pacific Gas and Electric
Company
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, claims against Pacific Gas and Electric Company on
behalf of approximately 2,800 plaintiffs were pending in eight
civil actions filed in California courts (known collectively as
the "Aguayo Litigation"). Two of these 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. Plaintiffs in both
actions have agreed to dismiss PG&E Corporation as a defendant.
Each of the 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 March 30, 1998, a Los Angeles Superior Court judge dismissed
the claims of 240 plaintiffs in Aguayo v. Pacific Gas and
Electric Company who were neither personally exposed to chromium
nor yet conceived at the time of their parents' alleged exposure.
The judge found that current California law precludes these types
of preconception claims. It is expected that plaintiffs will
appeal this ruling.
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.
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
PG&E Corporation:
On April 15, 1998, PG&E Corporation held its annual meeting of
shareholders. At that meeting, the following matters were voted
as indicated:
1. Election of the following directors to serve until the next
annual meeting of shareholders or until their successors
shall be elected and qualified:
For Withheld
---------- ----------
Richard A. Clarke 277,313,530 6,999,929
Harry M. Conger 278,179,795 6,133,664
David A. Coulter 275,721,980 8,591,479
Lee Cox 278,165,313 6,148,146
William S. Davila 278,194,826 6,118,633
Robert D. Glynn, Jr. 278,236,860 6,076,599
David M. Lawrence, MD 277,866,616 6,446,843
Richard B. Madden 278,145,725 6,167,734
Mary S. Metz 278,089,765 6,223,694
Rebecca Q. Morgan 275,597,117 8,716,342
Carl E. Reichardt 277,990,791 6,322,668
John C. Sawhill 278,166,923 6,146,536
Alan Seelenfreund 278,142,639 6,170,820
Barry Lawson Williams 278,077,940 6,235,519
2. Ratification of the appointment of Arthur Andersen LLP as
independent public accountants for the year 1998:
For: 279,482,833
Against: 2,005,818
Abstain: 2,824,808
The proposal was approved by a majority of the shares present and
voting (including abstentions) which shares voting affirmatively
also constituted a majority of the required quorum.
Each of the shareholder proposals listed below was defeated as
the number of shares voting affirmatively on each proposal
constituted less than a majority of the shares voting and present
(including abstentions) with respect to each proposal.
3. Consideration of a shareholder proposal to appoint
independent directors to key Board committees:
For: 72,457,935
Against: 158,238,439
Abstain: 9,002,693
Broker non-votes:(1) 44,614,392
4. Consideration of a shareholder proposal regarding super
majority voting:
For: 96,676,182
Against: 134,458,016
Abstain: 8,564,869
Broker non-votes:(1) 44,614,392
5. Consideration of a shareholder proposal regarding cumulative
voting:
For: 60,562,835
Against: 165,694,235
Abstain: 13,441,997
Broker non-votes:(1) 44,614,392
- --------------------
(1) A non-vote occurs when a broker or other nominee holding
shares for a beneficial owner votes on one proposal, but does not
vote on another proposal because the broker or other nominee does
not have discretionary voting power and has not received
instructions from the beneficial owner.
6. Consideration of a shareholder proposal regarding director
compensation:
For: 20,512,623
Against: 208,057,428
Abstain: 11,129,016
Broker non-votes:(1) 44,614,392
Pacific Gas and Electric Company:
On April 15, 1998, Pacific Gas and Electric Company held its
annual meeting of shareholders. Shares of capital stock of
Pacific Gas and Electric Company consist of shares of common
stock and shares of first preferred stock. PG&E Corporation, as
owner of all of the 409,120,387 outstanding shares of common
stock, holds approximately 95% of the combined voting power of
the outstanding capital stock of Pacific Gas and Electric
Company. PG&E Corporation voted all of its shares of common
stock for the nominees named in the joint proxy statement, for
the ratification of the appointment of Arthur Andersen LLP as
independent public accountants for the year 1998, and for the
management proposal to decrease the minimum number of directors.
The balance of the votes shown below were cast by holders of
shares of first preferred stock. At the annual meeting, the
following matters were voted as indicated:
1. Election of the following directors to serve until the next
annual meeting of shareholders or until their successors
shall be elected and qualified:
For Withheld
----------- -----------
Richard A. Clarke 423,365,574 269,854
Harry M. Conger 423,368,303 267,125
David A. Coulter 423,366,425 269,003
C. Lee Cox 423,370,269 265,159
William S. Davila 423,372,395 263,033
Robert D. Glynn, Jr. 423,374,990 260,438
David M. Lawrence, MD 423,366,246 269,182
Richard B. Madden 423,370,055 265,373
Mary S. Metz 423,361,953 273,475
Rebecca Q. Morgan 423,358,458 276,970
Carl E. Reichardt 423,362,050 273,378
John C. Sawhill 423,360,841 274,587
Alan Seelenfreund 423,365,942 269,486
Gordon R. Smith 423,374,019 261,409
Barry Lawson Williams 423,362,357 273,071
2. Ratification of the appointment of Arthur Andersen LLP as
independent public accountants for the year 1998:
For: 423,229,793
Against: 138,185
Abstain: 267,450
- --------------------
(1) A non-vote occurs when a broker or other nominee holding
shares for a beneficial owner votes on one proposal, but does not
vote on another proposal because the broker or other nominee does
not have discretionary voting power and has not received
instructions from the beneficial owner.
3. Management proposal regarding decrease in the minimum number
of directors (Item 7 in the joint proxy statement):
For: 423,002,572
Against: 249,621
Abstain: 383,235
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 three months ended March 31, 1998 was 2.66.
Pacific Gas and Electric Company's earnings to combined fixed
charges and preferred stock dividends ratio for the three months
ended March 31, 1998 was 2.50. The statement of the foregoing
ratios, together with the statements of the computation of the
foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are
included herein for the purpose of incorporating such information
and exhibits into Registration Statement Nos. 33-62488, 33-64136,
33-50707 and 33-61959, relating to Pacific Gas and Electric
Company's various classes of debt and first preferred stock
outstanding.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 3.1 Restated Articles of Incorporation of Pacific Gas
and Electric Company effective as of May 6, 1998
Exhibit 3.2 Bylaws of Pacific Gas and Electric Company, dated
May 6, 1998
Exhibit 10.1 PG&E Corporation Director Grantor Trust Agreement
dated April 1, 1998
Exhibit 10.2 PG&E Corporation Officer Grantor Trust Agreement
dated April 1, 1998
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
Exhibit 27.1 Financial Data Schedule for the quarter ended
March 31, 1998 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
March 31, 1998 for Pacific Gas and Electric
Company
(b) Reports on Form 8-K during the first quarter of 1998 and
through the date hereof (2):
1. January 22, 1998 (as amended by Form 8-K/A dated February 5, 1998)
Item 5. Other Events
A. Performance Incentive Plan - Year-to-date Financial
Results
B. 1997 Consolidated Earnings (unaudited)
C. Accelerated Share Repurchase Program
2. April 16, 1998
Item 5. Other Events
A. First Quarter 1998 Consolidated Earnings (unaudited)
B. Pacific Gas and Electric Company's General Rate Case
Proceeding
- --------------------
(2) 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)
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
May 15, 1998 By______________________________
CHRISTOPHER P. JOHNS
Controller
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company)
Exhibit Index
Exhibit No. Description of Exhibit
3.1 Restated Articles of Incorporation of Pacific Gas
and Electric Company effective as of May 6, 1998
3.2 Bylaws of Pacific Gas and Electric Company, dated
May 6, 1998
10.1 PG&E Corporation Director Grantor Trust Agreement
dated April 1, 1998
10.2 PG&E Corporation Officer Grantor Trust Agreement
dated April 1, 1998
11 Computation of Earnings Per Common Share
12.1 Computation of Ratio of Earnings to Fixed Charges
for Pacific Gas and Electric Company
12.2 Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
27.1 Financial Data Schedule for the quarter ended
March 31, 1998 for PG&E Corporation
27.2 Financial Data Schedule for the quarter ended
March 31, 1998 for Pacific Gas and Electric
Company