FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
----------------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1998
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
---------- ----------
Exact Name of
Commission Registrant State or other IRS Employer
File as specified Jurisdiction of Identification
Number in its charter Incorporation Number
- ----------- -------------- --------------- --------------
1-12609 PG&E Corporation California 94-3234914
1-2348 Pacific Gas and California 94-0742640
Electric Company
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California 94177 San Francisco, California
94105
- ------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Pacific Gas and Electric Company PG&E Corporation
(415) 973-7000 (415) 267-7000
- -------------------------------------------------------------------
Registrant's telephone number, including area code
Indicate by check mark whether the registrants (1) have filed
all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding twelve
months (or for such shorter period that the registrant was
required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.
Yes X No
---------- -----------
Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.
Common Stock Outstanding October 23, 1998:
PG&E Corporation 382,515,765 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBR 30, 1998
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME........................1
CONDENSED BALANCE SHEET.................................2
STATEMENT OF CASH FLOWS ................................3
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME........................4
CONDENSED BALANCE SHEET.................................5
STATEMENT OF CASH FLOWS.................................6
NOTE 1: GENERAL...........................................7
NOTE 2: THE ELECTRIC BUSINESS.............................9
NOTE 3: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED DEBENTURES...........16
NOTE 4: COMMITMENTS AND CONTINGENCIES....................16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF CONSOLIDATED
RESULTS OF OPERATIONS AND FINANCIAL CONDITION.............18
RESULTS OF OPERATIONS.....................................20
Common Stock Dividend..................................20
Earnings Per Common Share..............................21
Utility Results........................................21
Unregulated Business Results...........................22
FINANCIAL CONDITION.......................................22
COMPETITION AND CHANGING REGULATORY ENVIRONMENT...........22
THE UTILITY ELECTRIC GENERATION BUSINESS..................22
Competitive Market Framework...........................22
Electric Transition Plan...............................23
Rate Freeze and Rate Reduction.........................24
Transition Cost Recovery...............................24
Utility Generation Divestiture.........................26
Utility Generation Impairment..........................27
Customer Impacts of Transition Plan....................28
California Voter Initiative............................28
THE UTILITY ELECTRIC TRANSMISSION BUSINESS................29
THE UTILITY ELECTRIC DISTRIBUTION BUSINESS................30
THE UTILITY GAS BUSINESS..................................30
UNREGULATED BUSINESS OPERATIONS...........................31
PG&E CORPORATION..........................................31
ACQUISITIONS AND SALES....................................31
YEAR 2000.................................................32
LIQUIDITY AND CAPITAL RESOURCES
Sources of Capital.....................................35
Utility Cost of Capital................................36
1999 General Rate Case.................................37
Environmental Matters..................................37
Legal Matters..........................................37
Risk Management Activities.............................38
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................38
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.........................................39
ITEM 5. OTHER INFORMATION.........................................40
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................40
SIGNATURE..........................................................42
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 Nine months ended
September 30, September 30,
1998 1997 1998 1997
-------- -------- -------- -------
Operating Revenues
Utility $ 2,563 $ 2,541 $ 6,706 $ 7,094
Energy commodities and services 2,744 1,522 7,741 3,417
-------- -------- -------- --------
Total operating revenues 5,307 4,063 14,447 10,511
-------- -------- -------- --------
Operating Expenses
Cost of energy for utility 714 779 1,949 2,162
Cost of energy commodities and services 2,557 1,412 7,177 3,165
Operating and maintenance, net 925 771 2,041 2,324
Depreciation and decommissioning 569 473 1,713 1,397
-------- -------- -------- --------
Total operating expenses 4,765 3,435 12,880 9,048
-------- -------- -------- --------
Operating Income 542 628 1,567 1,463
Interest expense, net 199 174 604 497
Other income 8 20 24 114
-------- -------- -------- --------
Income Before Income Taxes 351 474 987 1,080
Income taxes 141 217 464 458
-------- -------- -------- --------
Net Income $ 210 $ 257 $ 523 $ 622
======== ======== ======== ========
Weighted Average Common Shares
Outstanding 382 414 382 407
Earnings Per Common Share, Basic and Diluted $ .55 $ .62 $ 1.37 $ 1.53
Dividends Declared Per Common Share $ .30 $ .30 $ .90 $ .90
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PG&E CORPORATION
CONDENSED BALANCE SHEET
(in millions)
Balance at September 30, December 31,
1998 1997
------------ -----------
ASSETS
Current Assets
Cash and cash equivalents $ 278 $ 237
Short-term investments 33 1,160
Accounts receivable
Customers, net 1,722 1,514
Regulatory balancing accounts 277 658
Energy marketing 736 830
Inventories and prepayments 792 626
-------- --------
Total current assets 3,838 5,025
Property, Plant, and Equipment
Utility 24,067 24,185
Gas transmission 3,385 3,484
Other 2,548 57
-------- --------
Total property, plant, and equipment (at original cost) 30,000 27,726
Accumulated depreciation and decommissioning (11,794) (11,617)
-------- --------
Net property, plant, and equipment 18,206 16,109
Other Noncurrent Assets
Regulatory assets 6,034 6,700
Nuclear decommissioning funds 1,070 1,024
Other 2,490 1,699
-------- --------
Total noncurrent assets 9,594 9,423
-------- --------
TOTAL ASSETS $ 31,638 $ 30,557
======== ========
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 1,937 $ 103
Current portion of long-term debt 358 734
Current portion of rate reduction bonds 197 125
Accounts payable
Trade creditors 770 754
Other 455 466
Energy marketing 587 758
Accrued taxes 725 226
Other 1,077 893
-------- --------
Total current liabilities 6,106 4,059
Noncurrent Liabilities
Long-term debt 7,060 7,584
Rate reduction bonds 2,511 2,776
Deferred income taxes 3,717 4,029
Deferred tax credits 294 339
Other 3,211 1,978
-------- --------
Total noncurrent liabilities 16,793 16,706
Preferred Stock of Subsidiary With Mandatory Redemption Provisions 137 137
Utility Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures 300 300
Stockholders' Equity
Preferred stock of subsidiary without mandatory redemption provisions
Nonredeemable 145 145
Redeemable 198 313
Common stock 5,848 6,366
Reinvested earnings 2,111 2,531
-------- --------
Total stockholders' equity 8,302 9,355
Commitments and Contingencies (Notes 2 and 4) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 31,638 $ 30,557
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PG&E CORPORATION
STATEMENT OF CASH FLOWS
(in millions)
For the nine months ended September 30, 1998 1997
---------- ----------
Cash Flows From Operating Activities
Net income $ 523 $ 622
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning, and amortization 1,792 1,489
Deferred income taxes and tax credits-net (309) (196)
Other deferred charges and noncurrent liabilities (1,071) 136
Gain on sale of assets - (120)
Loss on sale of assets 21 -
Net effect of changes in operating assets
and liabilities:
Accounts receivable 704 (52)
Regulatory balancing accounts receivable 618 2
Inventories (45) (46)
Accounts payable (118) (94)
Accrued taxes 501 321
Other working capital (101) (73)
Other-net - 179
--------- ---------
Net cash provided by operating activities 2,515 2,168
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (1,262) (1,181)
Investments in unregulated projects 17 (165)
Acquisitions (425) (41)
Proceeds from sale of assets 58 -
Other-net 218 153
--------- ---------
Net cash used by investing activities (1,394) (1,234)
--------- ---------
Cash Flows From Financing Activities
Common stock issued 48 40
Common stock repurchased (1,159) (704)
Long-term debt issued 139 363
Long-term debt matured, redeemed, or repurchased-net (1,295) (436)
Short-term debt issued (redeemed)-net 507 643
Preferred stock redeemed or repurchased (105) (7)
Dividends paid (377) (389)
Other-net 35 (20)
--------- ---------
Net cash used by financing activities (2,207) (510)
--------- ---------
Net Change in Cash and Cash Equivalents (1,086) 424
Cash and Cash Equivalents at January 1 1,397 143
--------- ---------
Cash and Cash Equivalents at September 30 $ 311 $ 567
--------- ---------
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 527 $ 372
Income taxes 264 352
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME
(in millions)
Three months ended Nine months ended
September 30, September 30,
1998 1997 1998 1997
-------- -------- -------- ------
Electric utility $ 2,226 $ 2,161 $ 5,496 $ 5,760
Gas utility 337 380 1,210 1,334
-------- -------- -------- --------
Total operating revenues 2,563 2,541 6,706 7,094
-------- -------- -------- --------
Operating Expenses
Cost of electric energy 663 730 1,616 1,837
Cost of gas 51 49 333 325
Operating and maintenance, net 641 695 2,055 2,159
Depreciation and decommissioning 528 441 1,602 1,332
Provision for regulatory adjustment mechanisms 154 - (349) -
-------- -------- -------- --------
Total operating expenses 2,037 1,915 5,257 5,653
-------- -------- -------- --------
Operating Income 526 626 1,449 1,441
Interest expense, net 160 146 493 437
Other income and (expense) 7 17 78 40
-------- -------- -------- -------
Income Before Income Taxes 373 497 1,034 1,044
Income taxes 168 220 480 465
-------- -------- -------- -------
Net Income 205 277 554 579
Preferred dividend requirement and
redemption premium 6 8 21 25
-------- -------- -------- -------
Income Available for Common Stock $ 199 $ 269 $ 533 $ 554
======== ======== ======== =======
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED BALANCE SHEET
(in millions)
Balance at
September 30, December 31,
1998 1997
----------- -----------
ASSETS
Current Assets
Cash and cash equivalents $ 78 $ 80
Short-term investments 15 1,143
Accounts receivable
Customers, net 1,295 1,204
Regulatory balancing accounts 277 658
Related parties accounts receivable 28 459
Inventories and prepayments 482 523
-------- --------
Total current assets 2,175 4,067
Property, Plant, and Equipment
Electric 17,006 17,246
Gas 7,061 6,939
-------- --------
Total property, plant, and equipment (at original cost) 24,067 24,185
Accumulated depreciation and decommissioning (11,209) (11,134)
-------- --------
Net property, plant, and equipment 12,858 13,051
Other Noncurrent Assets
Regulatory assets 5,991 6,646
Nuclear decommissioning funds 1,070 1,024
Other 374 359
-------- --------
Total noncurrent assets 7,435 8,029
-------- --------
TOTAL ASSETS $ 22,468 $ 25,147
======== ========
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 10 $ -
Current portion of long-term debt 275 655
Current portion of rate reduction bonds 197 125
Accounts payable
Trade creditors 514 441
Related parties 61 134
Other 414 424
Accrued taxes 494 229
Deferred income taxes 52 149
Other 554 527
-------- --------
Total current liabilities 2,571 2,684
Noncurrent Liabilities
Long-term debt 5,569 6,143
Rate reduction bonds 2,511 2,776
Deferred income taxes 3,000 3,304
Deferred tax credits 294 338
Other 1,807 1,810
-------- --------
Total noncurrent liabilities 13,181 14,371
Preferred Stock of Subsidiary With Mandatory Redemption Provisions 137 137
Company Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures 300 300
Stockholders' Equity
Preferred stock without mandatory redemption provisions
Nonredeemable 145 145
Redeemable 142 257
Common stock 3,806 4,582
Reinvested earnings 2,186 2,671
-------- --------
Total stockholders' equity 6,279 7,655
Commitments and Contingencies (Notes 2 and 4) -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 22,468 $ 25,147
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CASH FLOWS
(in millions)
For the nine months ended September 30, 1998 1997
-------- --------
Cash Flows From Operating Activities
Net income $ 554 $ 579
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, decommissioning, and amortization 1,697 1,424
Deferred income taxes and tax credits-net (297) (220)
Other deferred charges and noncurrent liabilities (243) 132
Provision for regulatory adjustment mechanisms (349) -
Net effect of changes in operating assets
and liabilities:
Accounts receivable 339 (163)
Regulatory balancing accounts receivable 618 2
Inventories 7 (17)
Accounts payable 116 (116)
Accrued taxes 265 336
Other working capital 24 (60)
Other-net 24 23
--------- ---------
Net cash provided by operating activities 2,755 1,920
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (963) (1,116)
Other-net 297 (90)
--------- ---------
Net cash used by investing activities (666) (1,206)
--------- ---------
Cash Flows From Financing Activities
Common stock repurchased (1,600) -
Long-term debt issued 2 355
Long-term debt matured, redeemed, or repurchased-net (1,175) (334)
Short-term debt issued (redeemed)-net - 132
Preferred stock redeemed or repurchased (107) -
Dividends paid (337) (548)
Other-net (2) (10)
--------- ---------
Net cash used by financing activities (3,219) (405)
Net Change in Cash and Cash Equivalents (1,130) 309
Cash and Cash Equivalents at January 1 1,223 143
--------- ---------
Cash and Cash Equivalents at September 30 $ 93 $ 452
--------- ---------
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 401 $ 329
Income taxes 587 406
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: GENERAL
Basis of Presentation:
- ----------------------
This Quarterly Report Form 10-Q is a combined report of PG&E Corporation and
Pacific Gas and Electric Company (the Utility), a regulated subsidiary of
PG&E Corporation. The Notes to Consolidated Financial Statements apply to
both PG&E Corporation and the Utility. PG&E Corporation's consolidated
financial statements include the accounts of PG&E Corporation and its wholly
owned and controlled subsidiaries, including the Utility (collectively, the
Corporation). The Utility's consolidated financial statements include its
accounts as well as those of its wholly owned and controlled subsidiaries.
The Utility's financial position and results of operations are the
principal factors affecting the Corporation's consolidated financial
position and results of operations. This quarterly report should be read
in conjunction with the Corporation's and the Utility's Consolidated
Financial Statements and Notes to Consolidated Financial Statements
incorporated by reference in their combined 1997 Annual Report Form on 10-K.
PG&E Corporation believes that the accompanying statements reflect all
adjustments necessary to present a fair statement of the consolidated
financial position and results of operations for the interim periods. All
material adjustments are of a normal recurring nature unless otherwise
disclosed in this Form 10-Q. All significant intercompany transactions have
been eliminated from the consolidated financial statements. Certain amounts
in the prior year's consolidated financial statements have been reclassified
to conform to the 1998 presentation. Results of operations for interim
periods are not necessarily indicative of results to be expected for a full
year.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions. These estimates and assumptions affect the reported amounts of
revenues, expenses, assets, and liabilities and the disclosure of
contingencies. Actual results could differ from these estimates.
Acquisitions and Sales:
- -----------------------
In July 1998, the Corporation sold its Australian energy holdings to Duke
Energy International, LLP (DEI), a subsidiary of Duke Energy Corporation.
The assets, located in the southeast corner of the Australian state of
Queensland, include a 627-kilometer gas pipeline, pipeline operations, and
trading and marketing operations.
The sale to DEI represents a premium on the price in local currency of
the Corporation's 1996 investment in the assets. However, the transaction
resulted in a non-recurring charge of $.06 per share in the second quarter,
primarily due to the 22 percent currency devaluation of the Australian
dollar against the U.S. dollar during the past two years.
On September 1, 1998, the Corporation, through its subsidiary U.S.
Generating Company (USGen), completed the acquisition of a portfolio of
electric generating assets and power supply contracts from the New England
Electric System (NEES) for $1.59 billion, plus $85 million for early
retirement and severance costs previously committed to by NEES. The
acquisition has been accounted for using the purchase method of accounting.
Accordingly, the purchase price has been preliminarily allocated to the
assets purchased and the liabilities assumed based upon the fair values at
the date of acquisition.
Including fuel and other inventories and transaction costs, the
Corporation's financing requirements total approximately $1.8 billion,
funded through $1.3 billion of USGen debt and a $425 million equity
contribution. The net purchase price has been preliminarily allocated as
follows: (1) Property, plant, and equipment of $2.3 billion; (2) Receivable
for support payments of $0.8 billion; and (3) Contractual obligations of
$1.3 billion. The assets include hydroelectric, coal, oil, and natural gas
generation facilities with a combined generating capacity of 4,000 megawatts
(MW). In addition, USGen assumed 25 multi-year power purchase agreements
representing an additional 800 MW of production capacity. USGen entered
into agreements with NEES as part of the acquisition, which: (1) provide
that NEES shall make support payments over the next ten years to USGen for
the purchase power agreements; and (2) require that USGen provide
electricity to NEES under contracts that expire over the next four to twelve
years.
The Corporation acquired NEES's generating facilities and power supply
contracts in anticipation of deregulation of the electric industry in
several New England states. In Massachusetts, electric industry
restructuring legislation opened retail competition in the electric
generation business on March 1, 1998. However, a referendum requesting
voters to approve the continuation of this legislation in Massachusetts is
on the November 1998 ballot. If the voters vote to reject the legislation,
then the restructuring legislation in Massachusetts will be repealed. The
Corporation does not expect that a repeal of the Massachusetts legislation,
which relates primarily to the retail electricity market, would have a
material impact on its results of operations or financial position.
Accounting for Risk Management Activities:
- ------------------------------------------
The Corporation, through its subsidiaries, engages in price risk management
activities for both non-hedging and hedging purposes. The Corporation
conducts non-hedging activities principally through its unregulated
subsidiary, PG&E Energy Trading. Derivative and other financial instruments
associated with the Corporation's electric power, natural gas, and related
non-hedging activities are accounted for using the mark-to-market method of
accounting.
Under mark-to-market accounting, the Corporation's electric power,
natural gas, and related non-hedging contracts, including both physical and
financial instruments, are recorded at market value, net of future servicing
costs and reserves. In the period of contract execution, income or expense
is recognized. The market prices used to value these transactions reflect
management's best estimates considering various factors, including market
quotes, time value, and volatility factors of the underlying commitments.
The values are adjusted to reflect the potential impact of liquidating a
position in an orderly manner over a reasonable period of time under present
market conditions.
Changes in the market value (determined by reference to recent
transactions) of these contract portfolios, resulting primarily from newly
originated transactions and the impact of commodity price and interest rate
movements, are recognized in operating revenue in the period of change.
These unrealized gains and losses and related reserves are recorded as
inventories and prepayments and other liabilities.
In addition to the non-hedging activities discussed above, the
Corporation may engage in hedging activities using futures, options, and
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies. The Corporation accounts for hedge
transactions under the deferral method. Initially, the Corporation defers
gains and losses on these transactions and classifies them as Inventories
and prepayments and Other liabilities in the Consolidated Balance Sheet.
When the hedged transaction occurs, the Corporation recognizes the gain or
loss in Cost of energy commodities and services or interest expense in the
Statement of Consolidated Income.
For regulatory reasons, the Utility manages price risk independently from
the activities in the Corporation's unregulated businesses. In the first
quarter of 1998, the California Public Utility Commission (CPUC) granted
approval for the Utility to use financial instruments to manage price
volatility of gas purchased for the Utility's electric generation portfolio.
The approval limits the Utility's outstanding financial instruments to $200
million, with downward adjustments occurring as the Utility divests its
fossil-fueled generation plants. (See Utility Generation Divestiture,
below.) Authority to use these risk management instruments ceases upon the
full divestiture of fossil-fueled generation plants or at the end of the
current electric rate freeze (see Rate Freeze and Rate Reduction, below),
whichever comes first.
In the second quarter of 1998, the CPUC granted conditional authority to
the Utility to use natural gas-based financial instruments to manage the
impact of natural gas prices on the cost of electricity purchased pursuant
to existing power purchase contracts. Under the authority granted in the
CPUC decision, no natural gas-based financial instruments shall have an
expiration date later than December 31, 2001. Further, if the rate freeze
ends before December 31, 2001, the Utility shall net any outstanding
financial instrument contracts through equal and opposite contracts, within
a reasonable amount of time. Also during the second quarter, the Utility
filed an application with the CPUC to use natural gas-based financial
instruments to manage price and revenue risks associated with its natural
gas transmission and storage assets. The Utility currently does not use
financial instruments to manage price risk.
The Corporation's net gains and losses associated with price risk
management activities for the three- and nine-month periods ended September
30, 1998, were not material.
In June 1998, the Financial Accounting Standards Board issued Statement
No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
which is required to be adopted in years beginning after June 15, 1999. The
Statement permits early adoption as of the beginning of any fiscal quarter.
The Corporation expects to adopt the new Statement no later than January 1,
2000. The Statement will require the Corporation to recognize all
derivatives, as defined in the Statement, on the balance sheet at fair
value. Derivatives, or any portion thereof, that are not effective hedges
must be adjusted to fair value through income. If the derivative is an
effective hedge, depending on the nature of the hedge, changes in the fair
value of derivatives either will be offset against the change in fair value
of the hedged assets, liabilities, or firm commitments through earnings or
will be recognized in other comprehensive income until the hedged item is
recognized in earnings. The Corporation currently is evaluating what the
effect of Statement 133 will be on the earnings and financial position of
the Corporation.
NOTE 2: The Utility Electric Generation Business
On March 31, 1998, California became one of the first states in the country
to allow open competition in the electric generation business. Today, many
Californians may choose an energy service provider, which will provide their
electric power generation. The Utility's customers may choose to purchase
electricity: (1) from the Utility; (2) from retail electricity providers
(for example, marketers including our energy service subsidiary, brokers,
and aggregators); or (3) directly from unregulated power generators. The
Utility expects to continue to provide distribution services to
substantially all electric consumers within its service territory.
Competitive Market Framework:
- -----------------------------
To create the competitive generation market, California established a Power
Exchange (PX) and an Independent Systems Operator (ISO). The PX sets
electricity prices in an open electric marketplace. The ISO, under the
jurisdiction of the Federal Energy Regulatory Commission (FERC), oversees
California's electric transmission grid to ensure that all generators have
comparable access and that the reliability of the system is maintained.
California utilities retained ownership of utility transmission facilities,
but relinquished operating control to the ISO. Starting March 31, 1998, the
ISO has scheduled the delivery of resources such as Qualifying Facilities
(QFs) and Diablo Canyon Nuclear Power Plant (Diablo Canyon). These
resources for operational or reliability reasons are considered "must-take"
units and operate under cost-of-service contracts. After scheduling must-
take resources, the ISO satisfies the remaining aggregate demand with
purchases from the PX and purchases of necessary generation and ancillary
services to maintain grid reliability. To meet the ISO's demand, the PX
accepts the lowest bids from competing electric providers, which establishes
a market price. Customers choosing to buy power directly from non-regulated
generators or retailers will pay for that generation based upon negotiated
contracts.
CPUC regulation requires the Utility to sell all of its generated
electric power and must-take electric power purchased from external power
producers to the PX. The Utility must then purchase all electric power for
its retail customers from the PX. For the three- and nine-month periods
ended September 30, 1998, the Cost of energy for utility, reflected on the
Statement of Consolidated Income, is comprised of the cost of PX purchases,
ancillary services purchased from the ISO, and the cost of Utility
generation, net of sales to the PX (in millions) as follows:
For the three- For the nine-
months ended months ended
September 30, 1998 September 30, 1998
------------------ ------------------
Cost of electric generation 576 1,566
Cost of purchases from the PX 379 489
Net cost of ancillary services 130 169
Proceeds from sales to the PX (422) (608)
------ ------
Cost of electric energy 663 1,616
Utility cost of gas 51 333
------ ------
Cost of energy for Utility 714 1,949
Electric Transition Plan:
- -------------------------
In developing state legislation to implement a competitive market, involved
parties believed that the Utility's market-based revenues would not be
sufficient to recover (that is, to collect from customers) all generation
costs. Many of these costs resulted from past CPUC decisions. To recover
these uneconomic costs, called transition costs, and to ensure a smooth
transition to the competitive environment, a transition plan was developed
in the form of state legislation to position California for the new market
environment. The California legislature passed the legislation and the
Governor signed it in 1996. As discussed below in California Voter
Initiative, on November 3, 1998, Californians will vote on Proposition 9,
which would overturn major portions of the current electric utility
restructuring legislation and would have a material adverse impact on the
Utility and the Corporation.
There are two principal elements of the transition plan established by
the restructuring legislation: (1) an electric rate freeze and rate
reduction; and (2) recovery of transition costs. Both of these elements are
discussed below. The restructuring legislation transition period ends
December 31, 2001. At the conclusion of the transition period, the Utility
will be at risk to recover any of its remaining generation costs through
market-based revenues.
Rate Freeze and Rate Reduction:
- -------------------------------
During 1997, electric rates for the Utility's customers were held at 1996
levels. Effective January 1, 1998, the Utility reduced electric rates for
its residential and small commercial customers by 10 percent and will hold
their rates at that level throughout the transition period. All other
electric customers' rates remained frozen at 1996 levels. The rate freeze
will continue until the end of the transition period. For the three- and
nine-month periods ended September 30, 1998, the 10 percent electric rate
reduction caused operating revenues to decrease by approximately $124
million and $304 million, respectively, as compared to the same periods in
1997.
As authorized by the restructuring legislation, to pay for the 10 percent
rate reduction, the Utility refinanced $2.9 billion of its transition costs
with rate reduction bonds, which have maturities ranging from three months
to ten years. The bonds defer recovery of a portion of the transition costs
until after the transition period. Pending the outcome of Proposition 9,
the Utility expects to recover the transition costs associated with the rate
reduction bonds over the term of the bonds.
Transition Cost Recovery:
- -------------------------
Transition costs are costs considered unavoidable and not expected to be
recovered through market-based revenues. These costs include: (1) the
above-market cost of Utility-owned generation facilities; (2) costs
associated with the Utility's long-term contracts to purchase power at
above-market prices from QFs and other power suppliers; and (3) generation-
related regulatory assets and obligations. (Regulatory assets are expenses
deferred in the current or prior periods to be included in rates in future
periods.)
The costs of Utility-owned generation facilities currently are included
in the Utility customers' rates. Above-market facility costs result when
book value is in excess of market value. Conversely, below-market facility
costs result when market value is in excess of book value. The total amount
of generation facility costs to be included as transition costs will be
based on the aggregate of above-market and below-market values. The above-
market portion of these costs is eligible for recovery as a transition cost.
The below-market portion of these costs will reduce other unrecovered
transition costs. A valuation of a Utility-owned generation facility where
the market value exceeds the book value could result in a material charge if
the valuation of the facility is determined based upon any method other than
a sale of the facility to a third party. This is because any excess of
market value over book value would be used to reduce other transition costs,
without increasing the book value of the plant assets.
The Utility will not be able to determine the exact amount of generation
facility costs that will be recoverable as transition costs until a market
valuation process (appraisal or sale) is completed for each of the Utility's
generation facilities. The first of these valuations occurred on July 1,
1998, when the Utility sold three Utility-owned electric generation plants
for $501 million. (See Utility Generation Divestiture, below.) For
generation facilities that the Utility has not divested, the CPUC will
approve the methodology to be used in the market valuation process.
The above-market portion of costs associated with the Utility's long-term
contracts to purchase power at above-market prices from QFs and other power
suppliers also are eligible to be recovered as transition costs. The
Utility has agreed to purchase electric power from these suppliers under
long-term contracts expiring on various dates through 2028. Over the life
of these contracts, the Utility estimates that it will purchase
approximately 345 million megawatt-hours at an aggregate average price of
6.5 cents per kilowatt-hour. To the extent that this price is above the
market price, the Utility expects to collect the difference between the
contract price and the market price from customers, as a transition cost,
over the terms of the contracts.
Generation-related regulatory assets, net of regulatory obligations, also
are eligible for transition cost recovery. As of September 30, 1998, the
Utility has accumulated approximately $6.0 billion of these assets net of
certain obligations, including the amounts reclassified from Property,
plant, and equipment, discussed in Utility Generation Impairment below.
The restructuring legislation specifies that the Utility must recover
most transition costs by December 31, 2001. This recovery period is
significantly shorter than the recovery period of the related assets prior
to restructuring. Effective January 1, 1998, as authorized by the CPUC in
consideration of the restructuring legislation, the Utility is recording
amortization of most generation-related regulatory assets over the
transition period. The CPUC believes that the shortened recovery period
reduces risks associated with recovery of all the Utility's generation
assets, including Diablo Canyon and hydroelectric facilities. Accordingly,
the Utility is receiving a reduced return for all of its Utility-owned
generation facilities. In 1998, the reduced return on common equity for
these facilities is 6.77 percent.
Although the Utility must recover most transition costs by December 31,
2001, certain transition costs may be included in customers' electric rates
after the transition period. These costs include: (1) certain employee-
related transition costs; (2) above-market payments under existing QF and
power-purchase contracts discussed above; and (3) unrecovered electric
industry restructuring implementation costs. In addition, transition costs
financed by the issuance of rate reduction bonds are expected to be
recovered over the term of the bonds through the collection of the Fixed
Transition Amount (FTA) charge from customers. Further, the Utility's
nuclear decommissioning costs are being recovered through a CPUC-authorized
charge, which will extend until sufficient funds exist to decommission
Diablo Canyon and Humboldt Nuclear Power Plants. During the rate freeze,
the FTA and nuclear decommissioning charges will not increase the Utility
customers' electric rates. Excluding these specific items, the Utility will
write off any transition costs not recovered during the transition period.
Effective January 1, 1998, the Utility has been collecting eligible
transition costs through a CPUC-authorized nonbypassable charge called the
competition transition charge (CTC). The amount of revenue collected from
frozen rates for recovery of transition costs is subject to seasonal
fluctuations in the Utility's sales volumes. Revenues available for the
purpose of recovering transition costs exceeded transition cost expense for
the three-month period ended September 30, 1998, by $154 million. During
the nine-month period ended September 30, 1998, transition cost expense
exceeded associated revenues available for recovery of transition costs by
$349 million. In accordance with CPUC rate treatment of transition costs,
the Utility deferred this excess as a regulatory asset. The Utility expects
to recover this regulatory asset during the remainder of the transition
period.
During the transition period, the CPUC will review the accounting methods
used by the Utility to recover transition costs and the amount of transition
costs requested for recovery. The CPUC is currently reviewing non-nuclear
transition costs amortized in the first half of 1998. The Utility expects
the CPUC to issue decisions regarding these reviews in the second quarter of
1999. At this time, the amount of transition cost disallowances, if any,
cannot be predicted.
In addition, on August 31, 1998, an independent accounting firm retained
by the CPUC completed its financial verification audit of the Utility's
Diablo Canyon plant accounts at December 31, 1996. The audit resulted in
the issuance of an unqualified opinion. The audit verified that Diablo
Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1
billion construction costs. (Sunk costs are costs associated with Utility-
owned generating facilities that are fixed and unavoidable and currently
included in the Utility customers' electric rates.) The independent
accounting firm also issued an agreed-upon special procedures report,
requested by the CPUC, which questioned $200 million of the $3.3 billion
sunk costs. The CPUC will review any proposed adjustments to Diablo
Canyon's recoverable costs, which resulted from the report. At this time,
the amount of transition cost disallowances, if any, cannot be predicted.
The Utility's ability to recover its transition costs during the
transition period will be dependent on several factors. The primary factor
is whether voters approve and the courts uphold Proposition 9, which would
eliminate transition cost recovery with certain exceptions. If Proposition
9 is defeated, the factors that continue to affect the Utility's ability to
recover transition costs include: (1) the continued application of the
regulatory framework established by the CPUC and state legislation; (2) the
amount of transition costs ultimately approved for recovery by the CPUC; (3)
the market value of the Utility-owned generation facilities; (4) future
Utility sales levels; (5) future Utility fuel and operating costs; (6) the
extent to which the Utility's authorized revenues to recover distribution
costs are increased or decreased; and (7) the market price of electricity.
Utility Generation Divestiture:
- -------------------------------
As part of electric industry restructuring, the Utility decided to sell its
fossil-fueled generation facilities. If the voters approve Proposition 9
(see California Voter Initiative, below,) then the Utility may alter its
current divestiture plan.
On July 1, 1998, the Utility completed the sale of three electric
Utility-owned fossil-fueled generating plants to Duke Energy Power Services
Inc. (Duke) for $501 million. These three fossil-fueled plants had a
combined book value at July 1, 1998, of approximately $351 million and a
combined capacity of 2,645 MW. The three power plants are located at Morro
Bay, Moss Landing, and Oakland.
The Utility will continue to operate and maintain the plants under a two-
year operating and maintenance agreement. Additionally, the Utility will
retain the liability for required environmental remediation of any pre-
closing soil or groundwater contamination at these plants. Although the
Utility is retaining such environmental remediation liability, the Utility
does not expect any material impact on its or PG&E Corporation's financial
position or results of operations. See Note 4, Environmental Remediation,
below.
In July 1998, the Utility agreed with the City and County of San
Francisco to permanently close Hunters Point Power Plant when reliable
alternative electricity resources are operational. The CPUC approved this
agreement in October 1998, allowing the Utility to recover the existing book
value of Hunters Point and the plant's environmental remediation and
decommissioning costs. Hunters Point is a fossil-fueled plant with a
generating capacity of 423 MW and a book value, including plant-related
regulatory assets, at September 30, 1998, of $33 million.
Subject to the outcome of Proposition 9, the Utility currently intends to
sell its fossil-fueled and geothermal facilities: Potrero, Pittsburg, Contra
Costa, and Geysers power plants. These fossil-fueled and geothermal
facilities have a combined generating capacity of 4,289 MW and a combined
book value at September 30, 1998, of approximately $592 million. The
Utility is scheduled to receive final bids to purchase these plants in
November 1998, and to complete the sale of these plants in 1999.
Any net gains from the sale of the Utility-owned fossil-fueled and
geothermal plants will be used to offset other transition costs. As a
result, the Utility does not believe the sales will have a material impact
on its results of operations.
In 1997, the Utility informed the CPUC that it does not intend to retain
its remaining 4,000 MW of hydroelectric facilities as part of the Utility.
These remaining facilities have a combined book value at September 30, 1998,
of approximately $1.6 billion. As discussed above, any method of
disposition of assets other than through sale to a third party could result
in a material charge to the extent that the market value, as determined by
the CPUC, is in excess of book value.
Utility Generation Impairment:
- ------------------------------
In the third quarter of 1997, the Emerging Issues Task Force (EITF) of the
Financial Accounting Standards Board reached a consensus on its issue No.
97-4, entitled "Deregulation of the Pricing of Electricity - Issues Related
to the Application of SFAS (Statement of Financial Accounting Standard) No.
71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises - Accounting for the Discontinuation of Application of
SFAS No. 71" (EITF 97-4), which provided authoritative guidance on the
applicability of SFAS No. 71 during the transition period. EITF 97-4
required the Utility to discontinue the application of SFAS No. 71 for the
generation portion of its operations as of July 24, 1997, the effective date
of EITF 97-4. EITF 97-4 requires that regulatory assets and liabilities
(both those in existence today and those created under the terms of the
transition plan established by the restructuring legislation) be allocated
to the portion of the business from which the source of the regulated cash
flows is derived.
Under the guidance of EITF 97-4 and SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," an impairment analysis was required of the generating assets no longer
subject to the guidance of SFAS No. 71. The Utility compared the cash flows
from all sources, including CTC revenues, to the cost of the generating
facilities and found that the assets were not impaired. During the second
quarter of 1998, the Staff of the Securities and Exchange Commission (SEC)
issued interpretive guidance regarding the application of EITF 97-4 and SFAS
No. 121. The guidance states that an impairment analysis should exclude CTC
revenues from the recovery stream. Under this interpretation, the Utility
performed the impairment analysis excluding CTC revenues and determined that
$3.9 billion of its generation facilities were impaired. Because the
Utility expects to recover the impaired assets as a transition cost under
the transition plan established by the restructuring legislation, discussed
above, the Utility recorded a regulatory asset for the impaired amounts as
required by EITF 97-4. Accordingly, at June 30, 1998, this amount was
reclassified from Property, Plant, and Equipment to Regulatory assets on the
accompanying balance sheets. In addition, prior year balances were
reclassified.
California Voter Initiative:
- ----------------------------
On November 3, 1998, California voters will vote on Proposition 9, an
initiative supported by various consumer groups.
Proposition 9 would overturn major provisions of California's electric
industry restructuring legislation. Proposition 9 proposes to: (1) require
the Utility and the other California investor-owned utilities to provide a
10 percent rate reduction to their residential and small commercial
customers in addition to the 10 percent rate reduction mandated by the
electric restructuring legislation; (2) eliminate transition cost recovery
for nuclear generation plants and related assets and obligations (other than
reasonable decommissioning costs); (3) eliminate transition cost recovery
for non-nuclear generation plants and related assets and obligations (other
than costs associated with QFs), unless the CPUC finds that the utilities
would be deprived of the opportunity to earn a fair rate of return; and (4)
prohibit the collection of any customer charges necessary to pay principal
and interest on the rate reduction bonds or, if a court finds that such
prohibition is not legal, require that utility rates be reduced to fully
offset the cost of the customer surcharges.
If the voters approve Proposition 9, then legal challenges by the
California utilities and others, including the Utility, would ensue. The
Utility intends to vigorously challenge Proposition 9 as unconstitutional
and to seek an immediate stay of its provisions pending court review of the
merits of its challenge.
If Proposition 9 is approved, and if the Utility were unable to conclude
that it is probable that Proposition 9 ultimately would be found invalid,
then under applicable accounting principles the Utility would be required to
write off generation-related regulatory assets, which would no longer be
probable of recovery because of reductions in future revenues. The Utility
anticipates that such a write-off would range from a minimum of
approximately $2.2 billion pre-tax to a maximum of approximately $5.0
billion pre-tax. This pre-tax loss would result in an after-tax loss
ranging from $1.3 billion to $2.9 billion, or $3 to $8 per share. The
amount of the write-off is dependent on how the courts and regulatory
agencies interpret and apply the provisions of Proposition 9. The maximum
$2.9 billion write-off would represent 48% of the Utility's total common
stockholders' equity of $6.0 billion at September 30, 1998.
The $2.9 billion maximum after-tax loss would eliminate the Utility's
retained earnings of $2.2 billion at September 30, 1998, and the Utility
would be unable to meet certain capital-related regulatory and legal
conditions. In addition, this loss would reduce the common equity ratio of
the Utility's ratemaking capital structure from approximately 48% to
approximately 32%, which is below the 48% equity ratio mandated by the CPUC.
Such a loss would severely impair the Utility's ability to pay dividends to
its preferred shareholders and the Corporation's ability to pay dividends to
its common shareholders. Also, the Utility is concerned that its credit
rating could drop to low investment grade or even below investment grade.
This would immediately and substantially reduce the market value of the
Utility's $5.8 billion in debt securities, increase the cost of raising new
debt capital, and may preclude the use of certain financial instruments for
raising capital.
The duration and amount of the rate decrease contemplated by Proposition
9 is uncertain and, if Proposition 9 is approved, will be subject to
interpretation by the courts and regulatory agencies. However, if all
provisions of Proposition 9 ultimately are upheld against legal challenge
and interpreted in an adverse manner, the amount of the average earnings
reductions could be approximately $200 million per year, or over $16 million
per month, from now through 2001 (assuming rates are reduced to offset the
charges for the rate reduction bonds) and approximately $50 million per year
from 2002 (based on rates under current regulatory decisions, assuming such
decisions are in effect after the latest date on which the rate freeze would
otherwise end) to 2007 (the longest maturity date of the rate reduction
bonds). The earnings reduction estimates depend on how the courts and
regulators interpret Proposition 9 and how future rate changes unrelated to
Proposition 9 (such as changes resulting from the General Rate Case
proceeding, discussed below) affect the Utility's electric revenues.
As discussed in Transition Cost Recovery, above, the Utility is
recovering most of its transition costs under a rate freeze through the
transition period, which ends by December 31, 2001. If Proposition 9 is
immediately implemented, even on a temporary basis pending judicial review,
then the Utility's opportunity to recover transition costs will be reduced
each month. Depending on market conditions, this reduction could amount to
as much as $115 million per month, on average.
In addition to the potential impacts on the Utility discussed above,
during any such litigation, Proposition 9 may adversely affect the secondary
market for the rate reduction bonds. Further, the collection of the FTA
charges necessary to pay the rate reduction bonds while the litigation is
pending would be precluded, unless an immediate stay is granted. Even if a
stay is granted immediately, there may be terms and conditions imposed in
connection with the stay that may adversely affect the cash flow for timely
interest payments on the rate reduction bonds. The failure to pay interest
when due could give rise to an event of default. Finally, if Proposition 9
is upheld against legal challenge, then the primary source for payments on
the rate reduction bonds would become unavailable and holders of the rate
reduction bonds could incur a loss of their investment.
NOTE 3: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF
TRUST HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES
The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust),
has outstanding 12 million shares of 7.90 percent cumulative quarterly
income preferred securities (QUIPS), with an aggregate liquidation value of
$300 million. Concurrent with the issuance of the QUIPS, the Trust issued
to the Utility 371,135 shares of common securities with an aggregate
liquidation value of approximately $9 million. The only assets of the Trust
are deferrable interest subordinated debentures issued by the Utility with a
face value of approximately $309 million, an interest rate of 7.90 percent,
and a maturity date of 2025.
NOTE 4: COMMITMENTS AND CONTINGENCIES
Nuclear Insurance:
- ------------------
The Utility has insurance coverage for property damage and business
interruption losses as a member of Nuclear Electric Insurance Limited
(NEIL). Under these policies, if a nuclear generating facility suffers a
loss due to a prolonged accidental outage, then the Utility may be subject
to maximum retrospective assessments of $17 million (property damage) and $6
million (business interruption), in each case per policy period, in the
event losses exceed the resources of NEIL.
The Utility has purchased primary insurance of $200 million for public
liability claims resulting from a nuclear incident. Secondary financial
protection provides an additional $9.7 billion in coverage, which is
mandated by federal legislation. It provides for loss sharing among
utilities owning nuclear generating facilities if a costly incident occurs.
If a nuclear incident results in claims in excess of $200 million, then the
Utility may be assessed up to $176 million per incident, with payments in
each year limited to a maximum of $20 million per incident.
Environmental Remediation:
- --------------------------
The Utility may be required to pay for environmental remediation at sites
where the Utility has been or may be a potentially responsible party under
the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) or the California Hazardous Substance Account Act. These sites
include former manufactured gas plant sites, power plant sites, and sites
used by the Utility for the storage or disposal of potentially hazardous
materials. Under CERCLA, the Utility may be responsible for remediation of
hazardous substances, even if the Utility did not deposit those substances
on the site.
The Utility records a liability when site assessments indicate
remediation is probable and a range of reasonably likely cleanup costs can
be estimated. The Utility reviews its remediation liability quarterly for
each identified site. The liability is an estimate of costs for site
investigations, remediation, operations and maintenance, monitoring, and
site closure. The remediation costs also reflect: (1) technology; (2)
enacted laws and regulations; (3) experience gained at similar sites; and
(4) the probable level of involvement and financial condition of other
potentially responsible parties. Unless there is a better estimate within
this range of possible costs, the Utility records the lower end of this
range.
The cost of the hazardous substance remediation ultimately undertaken by
the Utility is difficult to estimate. A change in the estimate may occur in
the near term due to uncertainty concerning the Utility's responsibility,
the complexity of environmental laws and regulations, and the selection of
compliance alternatives. The Utility had an accrued liability at September
30, 1998, of $282 million for hazardous waste remediation costs at
identified sites, including divested fossil-fueled power plants.
Environmental remediation at identified sites may be as much as $486 million
if, among other things, other potentially responsible parties are not
financially able to contribute to these costs or further investigation
indicates that the extent of contamination or necessary remediation is
greater than anticipated. The Utility estimated this upper limit of the
range of costs using assumptions least favorable to the Utility, based upon
a range of reasonably possible outcomes. Costs may be higher if the Utility
is found to be responsible for cleanup costs at additional sites or expected
outcomes change.
Of the $282 million liability, discussed above, the Utility has recovered
$97 million and expects to recover $162 million in future rates.
Additionally, the Utility is seeking recovery of its costs from insurance
carriers and from other third parties as appropriate.
The Corporation believes the ultimate outcome of these matters will not
have a material impact on its or the Utility's financial position or results
of operations.
Legal Matters:
- --------------
Chromium Litigation
Several civil suits are pending against the Utility in various California
state courts. The suits seek an unspecified amount of compensatory and
punitive damages for alleged personal injuries and, in some cases, property
damage, resulting from alleged exposure to chromium in the vicinity of the
Utility's gas compressor stations at Hinkley, Kettleman, and Topock,
California. Two of these cases also name PG&E Corporation as a defendant.
Currently, there are claims pending on behalf of approximately 2,300
plaintiffs.
The Utility is responding to the suits and asserting affirmative
defenses. The Utility will pursue appropriate legal defenses, including
statute of limitations or exclusivity of workers' compensation laws, and
factual defenses, including lack of exposure to chromium and the inability
of chromium to cause certain of the illnesses alleged.
The Corporation believes that the ultimate outcome of this matter will
not have a material impact on its or the Utility's financial position or
results of operations.
Texas Franchise Fee Litigation
In connection with PG&E Corporation's acquisition of Valero Energy
Corporation, now known as PG&E Gas Transmission, Texas Corporation (GTT),
GTT succeeded to the litigation described below.
GTT and various of its affiliates are defendants in at least two class
action suits and six separate suits filed by various Texas cities.
Generally, these cities allege, among other things, that: (1) owners or
operators of pipelines occupied city property and conducted pipeline
operations without the cities' consent and without compensating the cities;
and (2) the gas marketers failed to pay the cities for accessing and
utilizing the pipelines located in the cities to flow gas under city
streets. Plaintiffs also allege various other claims against the defendants
for failure to secure the cities' consent. Damages are not quantified.
In June 1998, a jury trial began in the case brought by the City of
Edinburg, on its own behalf and not as a class action, which involved, among
other things, a particular franchise agreement entered into by a former
subsidiary of GTT (now owned by Southern Union Gas Company (SU)) and the
City and certain conduct of the defendants. In August 1998, the jury
returned a verdict in favor of the City and awarded actual damages in the
approximate aggregate amount of $9.8 million, plus attorneys' fees of
approximately $3.5 million against GTT, SU and various affiliates. The jury
refused to award punitive damages against the GTT defendants. A hearing on
the plaintiff's motion for entry of judgment has been scheduled for December
1, 1998, after which the court will enter a judgment. At the hearing, the
court may provide guidance as to how the damages and attorneys' fees of
approximately $13.3 million will be apportioned among the parties. If an
adverse judgment is entered, GTT and its various subsidiaries intend to
appeal the judgment.
The Corporation believes that the ultimate outcome of these matters will
not have a material impact on its financial position or results of
operation.
ITEM 2. MANAGEMENT's DISCUSSION AND ANALYSIS OF CONSOLIDATED RESULTS OF
OPERATIONS AND FINANCIAL CONDITION
San Francisco-based PG&E Corporation provides integrated energy services.
PG&E Corporation's consolidated financial statements include the accounts of
PG&E Corporation and its various business lines:
- -Pacific Gas and Electric Company (Utility)
- -Unregulated Business Operations consisting of:
- Gas Transmission through PG&E Gas Transmission;
- Electric Generation through U.S. Generating Company (USGen);
- Energy Commodities and Services through PG&E Energy Trading
and PG&E Energy Services.
Overview:
- ---------
This is a combined Quarterly Report Form 10-Q of PG&E Corporation and
Pacific Gas and Electric Company. Therefore, our Management's Discussion
and Analysis of Consolidated Results of Operations and Financial Condition
(MD&A) applies to both PG&E Corporation and the Utility. PG&E Corporation's
consolidated financial statements include the accounts of PG&E Corporation
and its wholly owned and controlled subsidiaries, including the Utility
(collectively, the Corporation). Our Utility's consolidated financial
statements include its accounts as well as those of its wholly owned and
controlled subsidiaries. This MD&A should be read in conjunction with the
consolidated financial statements included herein. Further, this quarterly
report should be read in conjunction with the Corporation's and the
Utility's Consolidated Financial Statements and Notes to Consolidated
Financial Statements incorporated by reference in their combined 1997 Annual
Report on Form 10-K.
In this MD&A, we explain the results of operations for the three- and
nine-month periods ended September 30, 1998, as compared to the
corresponding periods in 1997, and discuss our financial condition. Our
discussion of financial condition includes:
- - changes in the energy industry and how we expect these changes to
influence future results of operations;
- - liquidity and capital resources, including discussions of capital
financing activities, and uncertainties that could affect future results;
and
- - risk management activities.
This Quarterly Report Form 10-Q, including our discussion of results of
operations and financial condition below, contains forward-looking
statements that involve risks and uncertainties. These statements are based
on the beliefs and assumptions of management and on information currently
available to management. Words such as "estimates," "expects,"
"anticipates," "plans," "believes," and similar expressions identify
forward-looking statements involving risks and uncertainties. Actual
results may differ materially from those expressed in the forward-looking
statements.
The most important factor that could affect future results and that would
cause actual results to differ materially from those expressed in the
forward looking statements, or from historical results, is the outcome and
potential impact of Proposition 9. If the voters approve and the courts
uphold Proposition 9, then Proposition 9 would overturn major provisions of
California's electric industry restructuring legislation. Other important
factors include, but are not limited to: (1) the ongoing restructuring of
the electric and gas industries in California and nationally; (2) the
outcome of the regulatory proceedings related to the restructuring; (3) the
Utility's ability to collect revenues sufficient to recover transition costs
in accordance with its transition cost recovery plan, specifically in light
of Proposition 9; (4) the planned sale of the Utility-owned fossil-fueled
electric generating plants, which may be altered if the voters approve
Proposition 9; (5) the impact of, and our ability to successfully integrate,
our acquisitions, including the New England Electric System (NEES) and the
Texas assets; (6) the potential impact from internal or external Year 2000
problems; (7) the outcome of the Utility's Cost of Capital proceeding; (8)
approval of the Utility's 1999 General Rate Case application providing the
Utility the opportunity to earn its authorized rate of return; (9) increased
competition; (10) our ability to expand into and to compete successfully in
new markets as the passage of Proposition 9 may stall electric industry
restructuring nationally; and (11) fluctuations in the prices of commodity
gas and electricity and our ability to successfully hedge against such price
risk. We discuss each of these items in greater detail below.
RESULTS OF OPERATIONS
In this section, we provide the components of our earnings for the three-
and nine-month periods ended September 30, 1998, and 1997. We then explain
why operating revenues and expenses varied from 1998 to 1997.
The following table shows results of operations for the three- and nine-
month periods ended September 30, 1998, and 1997, and total assets at
September 30, 1998, and 1997. The results for unregulated business
operations include the Corporation on a stand-alone basis.
(in millions)
Unregulated
Business Elimin-
Utility Operations ations Total
-------- ------------ ------- -------
For the three months ended
September 30,
1998
Operating revenues $ 2,563 $ 2,930 $ (186) $ 5,307
Operating expenses 2,037 2,914 (186) 4,765
------- ------- ------ -------
Operating income 526 16 - 542
Income available for
common stock 199 11 - 210
1997
Operating revenues $ 2,541 $ 1,565 $ (43) $ 4,063
Operating expenses 1,915 1,563 (43) 3,435
------- ------- ------- -------
Operating income 626 2 - 628
Income available for
common stock 269 (12) - 257
For the nine months ended
September 30,
1998
Operating revenues $ 6,706 $ 8,263 $ (522) $14,447
Operating expenses 5,257 8,145 (522) 12,880
------- ------- ------ -------
Operating income 1,449 118 - 1,567
Income available for
common stock 533 (10) - 523
Total assets at September 30 $22,468 $ 9,577 $ (347) $31,698
1997
Operating revenues $ 7,094 $ 3,485 $ (68) $10,511
Operating expenses 5,653 3,463 (68) 9,048
------- ------- ------- -------
Operating income 1,441 22 - 1,463
Income available for
common stock 554 68 - 622
Total assets at September 30 $23,895 $ 5,903 $ (383) $29,415
Common Stock Dividend:
- ----------------------
We base our common stock dividend on a number of financial considerations,
including sustainability, financial flexibility, and competitiveness with
investment opportunities of similar risk. Our current quarterly common
stock dividend is $.30 per common share, which corresponds to an annualized
dividend of $1.20 per common share.
The California Public Utility Commission (CPUC) requires the Utility to
maintain its CPUC-authorized capital structure, potentially limiting the
amount of dividends the Utility may pay the Corporation. At September 30,
1998, the Utility was in compliance with its CPUC-authorized capital
structure. The Utility believes that it will continue to meet this
condition in the future without affecting the Corporation's ability to pay
common stock dividends. However, if the voters approve and the courts
uphold Proposition 9, then the Utility would be required to write off
generation-related regulatory assets. Such a loss would severely impair the
Corporation's ability to pay dividends to its common shareholders.
Earnings Per Common Share:
- --------------------------
Earnings per common share for the three- and nine-month periods ended
September 30, 1998, decreased $.07 and $.16 cents, respectively, as compared
to the same periods in 1997. The activity discussed below affected earnings
per common share.
Utility Results:
- ----------------
Utility operating revenues increased $22 million for the three-month period
and decreased $388 million for the nine-month period ended September 30,
1998, as compared to the same periods in 1997. Operating revenues for the
three-month period ended September 30, 1998, increased primarily due to the
termination of our volumetric (ERAM) and energy cost (ECAC) revenue
balancing account, which reduced revenues by $122 million in 1997. This
increase is offset by lower billed revenues due to the 10% rate reduction
and reduced sales volumes. (The Utility replaced the ERAM and ECAC
balancing accounts with the transition cost balancing account (TCBA), which
impacts expenses instead of revenues as discussed in Transition Cost
Recovery, below.) Operating revenues for the nine-month period ended
September 30, 1998, decreased due to: (1) a 10 percent electric rate
reduction, discussed below, provided to residential and small commercial
customers, which caused a decrease of $124 million and $304 million for the
three- and nine-month periods ended September 30, 1998, respectively; (2) a
decrease in sales to medium and large electric customers, many of whom are
now purchasing their electricity directly from unregulated power generators;
and (3) a decrease in usage and sales to commercial and agricultural
electric customers resulting from their lower demand for irrigation water
pumping as a result of heavier rainfall in the current year.
Utility operating expenses increased $122 million for the three-month
period and decreased $396 million for the nine-month period ended September
30, 1998, as compared to the same periods in 1997. Operating expenses for
the nine-month period ended September 30, 1998, declined primarily as a
result of; (1) decreased fuel costs at power plants, primarily due to plant
sales; (2) decreased costs associated with Qualifying Facilities (QFs) due
to the expiration of the fixed price periods in many QF contracts; (3) lower
transmission pipeline demand charges; and (4) expense deferrals related to
electric industry restructuring. Increased expenses incurred for system
reliability and accelerated amortization of regulatory assets recovered
under the transition plan established by the restructuring legislation
partially offset these decreases. As previously indicated, electric
industry restructuring provides for recovery of certain costs in future
periods. Some costs, associated with the expense deferrals mentioned above,
will be recovered as electric sales volumes increase during seasonal
fluctuations. Others relate to transition costs, which will be recovered
over the term of the rate reduction bonds.
Unregulated Business Results:
- -----------------------------
Our unregulated business operations include those business activities that
are not directly regulated by the CPUC. Unregulated business operating
revenues for the three- and nine-month periods ended September 30, 1998,
increased approximately $1.4 billion and $4.8 billion, respectively, while
operating expenses increased approximately $1.4 billion and $4.7 billion,
respectively, as compared to the same periods in 1997. These increases were
due to operations associated with our energy commodities and services
activities and due to the acquisition of the natural gas operations of
Valero Energy Corporation in July 1997. Energy trading volumes continue to
increase over 1997 levels. The resultant operating revenue increases from
these activities, however, were partially offset by decreases in our Texas
operations from: (1) low natural gas transmission prices and volumes; and
(2) low differentials between natural gas liquids prices and the cost of
natural gas.
Unregulated business operations contributed $23 million more in net
income for the three-month period ended September 30, 1998, than in the same
period in 1997, and $78 million less in net income in the nine-month period
ended September 30, 1998, than in the same periods in 1997. The decrease
for the nine-month period ended September 30, 1998, is due to the loss on
sale of our Australian holdings (See Acquisitions and Sales, below.) The
decrease was also due to the $110 million gain that the Corporation
recognized in the second quarter 1997 on the sale of its interest in
International Generating Company, Ltd. The second quarter 1997 gain was
partially offset by write-downs of certain unregulated investments of
approximately $41 million.
FINANCIAL CONDITION
We begin this section by discussing the energy industry. We also discuss
how we are responding to restructuring on a national level, including a
recent acquisition. We then discuss liquidity and capital resources and our
risk management activities.
COMPETITION AND CHANGING REGULATORY ENVIRONMENT:
The Utility Electric Generation Business:
On March 31, 1998, California became one of the first states in the country
to allow open competition in the electric generation business. Today, many
Californians may choose an energy service provider, which will provide their
electric power generation. The Utility's customers may choose to purchase
electricity: (1) from the Utility; (2) from retail electricity providers
(for example, marketers including our energy service subsidiary, brokers,
and aggregators); or (3) directly from unregulated power generators. Our
Utility expects to continue to provide distribution services to
substantially all electric consumers within its service territory.
Competitive Market Framework:
- -----------------------------
To create the competitive generation market, California has established a
Power Exchange (PX) and an Independent Systems Operator (ISO). The PX sets
electricity prices in an open electric marketplace. The ISO, under the
jurisdiction of the Federal Energy Regulatory Commission (FERC), oversees
California's electric transmission grid to ensure that all generators have
comparable access and that the reliability of the system is maintained.
California utilities retained ownership of utility transmission facilities,
but relinquished operating control to the ISO. Starting March 31, 1998, the
ISO has scheduled the delivery of resources such as Qualifying Facilities
(QFs) and Diablo Canyon. These resources for operational or reliability
reasons are considered "must-take" units and operate under cost-of-service
contracts. After scheduling must-take resources, the ISO satisfies the
remaining aggregate demand with purchases from the PX and purchases of
necessary generation and ancillary services to maintain grid reliability.
To meet the ISO's demand, the PX accepts the lowest bids from competing
electric providers, which establishes a market price. Customers choosing to
buy power directly from non-regulated generators or retailers will pay for
that generation based upon negotiated contracts.
CPUC regulation requires the Utility to sell all of its generated
electric power and must-take electric power purchased from external power
producers to the PX. The Utility must then purchase all electric power for
its retail customers from the PX. For the three- and nine-month periods
ended September 30, 1998, the Cost of energy for utility, reflected on the
Statement of Consolidated Income, is comprised of the cost of PX purchases,
ancillary services purchased from the ISO, and the cost of Utility
generation, net of sales to the PX (in millions) as follows:
For the three- For the nine-
months ended months ended
September 30, 1998 September 30, 1998
------------------ ------------------
Cost of electric generation 576 1,566
Cost of purchases from the PX 379 489
Net cost of ancillary services 130 169
Proceeds from sales to the PX (422) (608)
------ ------
Cost of electric energy 663 1,616
Utility cost of gas 51 333
------ ------
Cost of energy for Utility 714 1,949
Electric Transition Plan:
- -------------------------
Over the past several years, we have taken steps to prepare for competition
in the electric generation business. We have worked with the CPUC to ensure
a smooth transition into the competitive market environment. In addition,
we have made strategic investments throughout the nation that will further
position us as a national energy provider.
In developing state legislation to implement a competitive market,
involved parties believed that our Utility's market-based revenues would not
be sufficient to recover (that is, to collect from customers) all generation
costs. Many of these costs resulted from past CPUC decisions. To recover
these uneconomic costs, called transition costs, and to ensure a smooth
transition to the competitive environment, a transition plan was developed
in the form of state legislation to position California for the new market
environment. The California Legislature passed the legislation and the
Governor signed it in 1996. As discussed below in California Voter
Initiative, on November 3, 1998, Californians will vote on Proposition 9,
which would overturn major portions of the current electric utility
restructuring legislation and would have a material adverse impact on the
Utility and the Corporation.
There are two principal elements of the transition plan established by
restructuring legislation: (1) an electric rate freeze and rate reduction;
and (2) recovery of transition costs. Both of these elements, and the
impact of the approved transition plan on our Utility's customers, are
discussed below. The restructuring legislation transition period ends
December 31, 2001. At the conclusion of the transition period, we will be
at risk to recover any of our Utility's remaining generation costs through
market-based revenues.
Rate Freeze and Rate Reduction:
- -------------------------------
During 1997, electric rates for our Utility's customers were held at 1996
levels. Effective January 1, 1998, the Utility reduced electric rates for
its residential and small commercial customers by 10 percent and will hold
their rates at that level throughout the transition period. All other
electric customers' rates remained frozen at 1996 levels. The rate freeze
will continue until the end of the transition period. For the three- and
nine-month periods ended September 30, 1998, the 10 percent rate reduction
caused operating revenues to decrease by approximately $124 million and $304
million, respectively, as compared to the same periods in 1997.
As authorized by the restructuring legislation, to pay for the 10 percent
rate reduction, the Utility refinanced $2.9 billion of its transition costs
with rate reduction bonds, which have maturities ranging from three months
to ten years. The bonds defer recovery of a portion of the transition costs
until after the transition period. Pending the outcome of Proposition 9,
the Utility expects to recover the transition costs associated with the rate
reduction bonds over the term of the bonds.
Transition Cost Recovery:
- -------------------------
Transition costs are costs considered unavoidable and not expected to be
recovered through market-based revenues. These costs include: (1) the
above-market cost of Utility-owned generation facilities; (2) costs
associated with the Utility's long-term contracts to purchase power at
above-market prices from QFs and other power suppliers; and (3) generation-
related regulatory assets and obligations. (Regulatory assets are expenses
deferred in the current or prior periods to be included in rates in future
periods.)
The costs of Utility-owned generation facilities currently are included
in the Utility customers' rates. Above-market facility costs result when
book value is in excess of market value. Conversely, below-market facility
costs result when market value is in excess of book value. The total amount
of generation facility costs to be included as transition costs will be
based on the aggregate of above-market and below-market values. The above-
market portion of these costs is eligible for recovery as a transition cost.
The below-market portion of these costs will reduce other unrecovered
transition costs. A valuation of a Utility-owned generation facility where
the market value exceeds the book value could result in a material charge if
the valuation of the facility is determined based upon any method other than
a sale of the facility to a third party. This is because any excess of
market value over book value would be used to reduce other transition costs,
without increasing the book value of the plant assets.
The Utility will not be able to determine the exact amount of generation
facility costs that will be recoverable as transition costs until a market
valuation process (appraisal or sale) is completed for each of the Utility's
generation facilities. The first of these valuations occurred on July 1,
1998, when the Utility sold three Utility-owned electric generation plants
for $501 million. (See Utility Generation Divestiture, below.) For
generation facilities that the Utility has not divested, the CPUC will
approve the methodology to be used in the market valuation process.
The above-market portion of costs associated with the Utility's long-term
contracts to purchase power at above-market prices from QFs and other power
suppliers also are eligible to be recovered as transition costs. The
Utility has agreed to purchase electric power from these suppliers under
long-term contracts expiring on various dates through 2028. Over the life
of these contracts, the Utility estimates that it will purchase
approximately 345 million megawatt-hours at an aggregate average price of
6.5 cents per kilowatt-hour. To the extent that this price is above the
market price, the Utility expects to collect the difference between the
contract price and the market price from customers, as a transition cost,
over the terms of the contracts.
Generation-related regulatory assets, net of regulatory obligations, also
are eligible for transition cost recovery. As of September 30, 1998, the
Utility has accumulated approximately $6.0 billion of these assets net of
certain obligations, including the amounts reclassified from Property,
plant, and equipment, discussed in Utility Generation Impairment below.
The restructuring legislation specifies that the Utility must recover
most transition costs by December 31, 2001. This recovery period is
significantly shorter than the recovery period of the related assets prior
to restructuring. Effective January 1, 1998, as authorized by the CPUC in
consideration of the restructuring legislation, the Utility is recording
amortization of most generation-related regulatory assets over the
transition period. The CPUC believes that the shortened recovery period
reduces risks associated with recovery of all the Utility's generation
assets, including Diablo Canyon and hydroelectric facilities. Accordingly,
the Utility is receiving a reduced return for all of its Utility-owned
generation facilities. In 1998, the reduced return on common equity for
these facilities is 6.77 percent.
Although the Utility must recover most transition costs by December 31,
2001, certain transition costs may be included in customers' electric rates
after the transition period. These costs include: (1) certain employee-
related transition costs; (2) above-market payments under existing QF and
power-purchase contracts discussed above; and (3) unrecovered electric
industry restructuring implementation costs. In addition, transition costs
financed by the issuance of rate reduction bonds are expected to be
recovered over the term of the bonds through the collection of the Fixed
Transition Amount (FTA) charge from customers. Further, the Utility's
nuclear decommissioning costs are being recovered through a CPUC-authorized
charge, which will extend until sufficient funds exist to decommission
Diablo Canyon and Humboldt Nuclear Power Plants. During the rate freeze,
the FTA and nuclear decommissioning charges will not increase the Utility
customers' electric rates. Excluding these specific items, the Utility will
write off any transition costs not recovered during the transition period.
Effective January 1, 1998, the Utility has been collecting eligible
transition costs through a CPUC-authorized nonbypassable charge called the
competition transition charge (CTC). The amount of revenue collected from
frozen rates for recovery of transition costs is subject to seasonal
fluctuations in the Utility's sales volumes. Revenues available for the
purpose of recovering transition costs exceeded transition cost expense for
the three-month period ended September 30, 1998, by $154 million. During
the nine-month period ended September 30, 1998, transition cost expense
exceeded associated revenues available for recovery of transition costs by
$349 million. In accordance with CPUC rate treatment of transition costs,
the Utility deferred this excess as a regulatory asset. The Utility expects
to recover this regulatory asset during the remainder of the transition
period.
During the transition period, the CPUC will review the accounting methods
used by the Utility to recover transition costs and the amount of transition
costs requested for recovery. The CPUC is currently reviewing non-nuclear
transition costs amortized in the first half of 1998. The Utility expects
the CPUC to issue decisions regarding these reviews in the second quarter of
1999. At this time, the amount of transition cost disallowances, if any,
cannot be predicted.
In addition, on August 31, 1998, an independent accounting firm retained
by the CPUC completed its financial verification audit of the Utility's
Diablo Canyon plant accounts at December 31, 1996. The audit resulted in
the issuance of an unqualified opinion. The audit verified that Diablo
Canyon sunk costs at December 31, 1996, were $3.3 billion of the total $7.1
billion construction costs. (Sunk costs are costs associated with Utility-
owned generating facilities that are fixed and unavoidable and currently
included in the Utility customers' electric rates.) The independent
accounting firm also issued an agreed-upon special procedures report,
requested by the CPUC, which questioned $200 million of the $3.3 billion
sunk costs. The CPUC will review any proposed adjustments to Diablo
Canyon's recoverable costs, which resulted from the report. At this time,
the amount of transition cost disallowances, if any, cannot be predicted.
The Utility's ability to recover its transition costs during the
transition period will be dependent on several factors. The primary factor
is whether voters approve and the courts uphold Proposition 9, which would
eliminate transition cost recovery with certain exceptions. If Proposition
9 is defeated, the factors that continue to affect the Utility's ability to
recover transition costs include: (1) the continued application of the
regulatory framework established by the CPUC and state legislation; (2) the
amount of transition costs ultimately approved for recovery by the CPUC; (3)
the market value of the Utility-owned generation facilities; (4) future
Utility sales levels; (5) future Utility fuel and operating costs; (6) the
extent to which the Utility's authorized revenues to recover distribution
costs are increased or decreased; and (7) the market price of electricity.
Utility Generation Divestiture:
- -------------------------------
As part of electric industry restructuring, the Utility decided to sell its
fossil-fueled generation facilities. If the voters approve Proposition 9
(see California Voter Initiative, below,) then the Utility may alter its
current divestiture plan.
On July 1, 1998, the Utility completed the sale of three electric
Utility-owned fossil-fueled generating plants to Duke Energy Power Services
Inc. (Duke) for $501 million. These three fossil-fueled plants had a
combined book value at July 1, 1998, of approximately $351 million and a
combined capacity of 2,645 MW. The three power plants are located at Morro
Bay, Moss Landing, and Oakland.
The Utility will continue to operate and maintain the plants under a two-
year operating and maintenance agreement. Additionally, the Utility will
retain the liability for required environmental remediation of any pre-
closing soil or groundwater contamination at these plants. Although the
Utility is retaining such environmental remediation liability, the Utility
does not expect any material impact on its or PG&E Corporation's financial
position or results of operations.
In July 1998, the Utility agreed with the City and County of San
Francisco to permanently close Hunters Point Power Plant when reliable
alternative electricity resources are operational. The CPUC approved this
agreement in October 1998, allowing the Utility to recover the existing book
value of Hunters Point and the plant's environmental remediation and
decommissioning costs. Hunters Point is a fossil-fueled plant with a
generating capacity of 423 MW and a book value, including plant-related
regulatory assets, at September 30, 1998, of $33 million.
Subject to the outcome of Proposition 9, the Utility currently intends to
sell its fossil-fueled and geothermal facilities: Potrero, Pittsburg, Contra
Costa, and Geysers power plants. These fossil-fueled and geothermal
facilities have a combined generating capacity of 4,289 MW and a combined
book value at September 30, 1998, of approximately $592 million. The
Utility is scheduled to receive final bids to purchase these plants in
November 1998, and to complete the sale of these plants in 1999.
Any net gains from the sale of our Utility-owned fossil-fueled and
geothermal plants will be used to offset other transition costs. As a
result, we do not believe the sales will have a material impact on our
results of operations.
In 1997, the Utility informed the CPUC that it does not intend to retain
its remaining 4,000 MW of hydroelectric facilities as part of the Utility.
These remaining facilities have a combined book value at September 30, 1998,
of approximately $1.6 billion. As discussed above, any method of
disposition of assets other than through sale to a third party could result
in a material charge to the extent that the market value, as determined by
the CPUC, is in excess of book value.
Utility Generation Impairment:
- ------------------------------
In the third quarter of 1997, the Emerging Issues Task Force (EITF) of the
Financial Accounting Standards Board reached a consensus on its issue No.
97-4, entitled "Deregulation of the Pricing of Electricity - Issues Related
to the Application of SFAS (Statement of Financial Accounting Standard) No.
71, Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises - Accounting for the Discontinuation of Application of
SFAS No. 71" (EITF 97-4), which provided authoritative guidance on the
applicability of SFAS No. 71 during the transition period. EITF 97-4
required the Utility to discontinue the application of SFAS No. 71 for the
generation portion of its operations as of July 24, 1997, the effective date
of EITF 97-4. EITF 97-4 requires that regulatory assets and liabilities
(both those in existence today and those created under the terms of the
transition plan established by the restructuring legislation) be allocated
to the portion of the business from which the source of the regulated cash
flows is derived.
Under the guidance of EITF 97-4 and SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of," an impairment analysis was required of the generating assets no longer
subject to the guidance of SFAS No. 71. The Utility compared the cash flows
from all sources, including CTC revenues, to the cost of the generating
facilities and found that the assets were not impaired. During the second
quarter of 1998, the Staff of the Securities and Exchange Commission (SEC)
issued interpretive guidance regarding the application of EITF 97-4 and SFAS
No. 121. The guidance states that an impairment analysis should exclude CTC
revenues from the recovery stream. Under this interpretation, the Utility
performed the impairment analysis excluding CTC revenues and determined that
$3.9 billion of its generation facilities were impaired. Because the
Utility expects to recover the impaired assets as a transition cost under
the transition plan established by the restructuring legislation, discussed
above, the Utility recorded a regulatory asset for the impaired amounts as
required by EITF 97-4. Accordingly, at June 30, 1998, this amount was
reclassified from Property, Plant, and Equipment to Regulatory assets on the
accompanying balance sheets. In addition, prior year balances were
reclassified.
Customer Impacts of Transition Plan:
- ------------------------------------
Effective March 31, 1998, all Californians may choose their electric
commodity provider. As of October 15, 1998, the Utility had accepted
approximately 63,000 requests to switch their electric commodity supplier
from the Utility to another electric commodity provider.
Regardless of the customer's choice of electric commodity provider,
during the transition period, customers will be billed for electricity used,
for transmission and distribution services, for public purpose programs, and
for recovery of transition costs. Customers who choose to purchase their
electricity from non-Utility energy providers will see a change in their
total bill only to the extent that their contracted electric commodity price
differs from the PX price. Transition costs are being recovered from
substantially all Utility distribution customers through a nonbypassable
charge regardless of their choice in commodity provider. We do not believe
that the availability of choice to our customers will have a material impact
on our ability to recover transition costs.
In addition to supplying commodity electric power, commodity electric
providers may choose the method of billing their customers and whether to
provide their customers with metering services. We are tracking cost
savings that result when billing, metering, and related services within our
Utility's service territory are provided by another entity. Once these cost
savings, or credits, are approved by the CPUC and the customer's energy
provider is performing billing and metering services, we will: (1) refund
the savings to customers where the Utility provides the billing for these
services; or (2) remit the savings to the electric providers where the
electric provider bills for these services. The electric providers then
will charge their customers for these services. To the extent that these
credits equate to our actual cost savings from reduced billing, metering,
and related services, we do not expect a material impact on the
Corporation's or the Utility's financial condition or results of operations.
California Voter Initiative:
- ----------------------------
On November 3, 1998, California voters will vote on Proposition 9, an
initiative supported by various consumer groups.
Proposition 9 would overturn major provisions of California's electric
industry restructuring legislation. Proposition 9 proposes to: (1) require
the Utility and the other California investor-owned utilities to provide a
10 percent rate reduction to their residential and small commercial
customers in addition to the 10 percent rate reduction mandated by the
electric restructuring legislation; (2) eliminate transition cost recovery
for nuclear generation plants and related assets and obligations (other than
reasonable decommissioning costs); (3) eliminate transition cost recovery
for non-nuclear generation plants and related assets and obligations (other
than costs associated with QFs), unless the CPUC finds that the utilities
would be deprived of the opportunity to earn a fair rate of return; and (4)
prohibit the collection of any customer charges necessary to pay principal
and interest on the rate reduction bonds or, if a court finds that such
prohibition is not legal, require that utility rates be reduced to fully
offset the cost of the customer surcharges.
If the voters approve Proposition 9, then legal challenges by the
California utilities and others, including the Utility, would ensue. The
Utility intends to vigorously challenge Proposition 9 as unconstitutional
and to seek an immediate stay of its provisions pending court review of the
merits of its challenge.
If Proposition 9 is approved, and if the Utility were unable to conclude
that it is probable that Proposition 9 ultimately would be found invalid,
then under applicable accounting principles the Utility would be required to
write off generation-related regulatory assets, which would no longer be
probable of recovery because of reductions in future revenues. The Utility
anticipates that such a write-off would range from a minimum of
approximately $2.2 billion pre-tax to a maximum of approximately $5.0
billion pre-tax. This pre-tax loss would result in an after-tax loss
ranging from $1.3 billion to $2.9 billion, or $3 to $8 per share. The
amount of the write-off is dependent on how the courts and regulatory
agencies interpret and apply the provisions of Proposition 9. The maximum
$2.9 billion write-off would represent 48% of the Utility's total common
stockholders' equity of $6.0 billion at September 30, 1998.
The $2.9 billion maximum after-tax loss would eliminate the Utility's
retained earnings of $2.2 billion at September 30, 1998, and the Utility
would be unable to meet certain capital-related regulatory and legal
conditions. In addition, this loss would reduce the common equity ratio of
the Utility's ratemaking capital structure from approximately 48% to
approximately 32%, which is below the 48% equity ratio mandated by the CPUC.
Such a loss would severely impair the Utility's ability to pay dividends to
its preferred shareholders and the Corporation's ability to pay dividends to
its common shareholders. Also, the Utility is concerned that its credit
rating could drop to low investment grade or even below investment grade.
This would immediately and substantially reduce the market value of the
Utility's $5.8 billion in debt securities, increase the cost of raising new
debt capital, and may preclude the use of certain financial instruments for
raising capital.
The duration and amount of the rate decrease contemplated by Proposition
9 is uncertain and, if Proposition 9 is approved, will be subject to
interpretation by the courts and regulatory agencies. However, if all
provisions of Proposition 9 ultimately are upheld against legal challenge
and interpreted in an adverse manner, the amount of the average earnings
reductions could be approximately $200 million per year, or over $16 million
per month, from now through 2001 (assuming rates are reduced to offset the
charges for the rate reduction bonds) and approximately $50 million per year
from 2002 (based on rates under current regulatory decisions, assuming such
decisions are in effect after the latest date on which the rate freeze would
otherwise end) to 2007 (the longest maturity date of the rate reduction
bonds). The earnings reduction estimates depend on how the courts and
regulators interpret Proposition 9 and how future rate changes unrelated to
Proposition 9 (such as changes resulting from the General Rate Case
proceeding, discussed below) affect the Utility's electric revenues.
As discussed in Transition Cost Recovery, above, the Utility is
recovering most of its transition costs under a rate freeze through the
transition period, which ends by December 31, 2001. If Proposition 9 is
immediately implemented, even on a temporary basis pending judicial review,
then the Utility's opportunity to recover transition costs will be reduced
each month. Depending on market conditions, this reduction could amount to
as much as $115 million per month, on average.
In addition to the potential impacts on the Utility discussed above,
during any such litigation, Proposition 9 may adversely affect the secondary
market for the rate reduction bonds. Further, the collection of the FTA
charges necessary to pay the rate reduction bonds while the litigation is
pending would be precluded, unless an immediate stay is granted. Even if a
stay is granted immediately, there may be terms and conditions imposed in
connection with the stay that may adversely affect the cash flow for timely
interest payments on the rate reduction bonds. The failure to pay interest
when due could give rise to an event of default. Finally, if Proposition 9
is upheld against legal challenge, then the primary source for payments on
the rate reduction bonds would become unavailable and holders of the rate
reduction bonds could incur a loss of their investment.
The Utility Electric Transmission Business:
Utility electric transmission revenues are under FERC jurisdiction. In
December 1997, the FERC put into effect rates to recover annual retail
electric transmission revenues of $301 million, effective March 31, 1998,
the operational date of the ISO and PX. The authorized revenues were
consistent with Utility electric transmission revenues in CPUC-authorized
1997 electric rates. In May 1998, the FERC allowed a $30 million increase
in retail electric transmission revenues, effective October 30, 1998. All
1998 retail electric transmission revenues are subject to refund pending
rate review proceedings by the FERC. The Utility does not expect a material
change in transmission revenues resulting from the FERC's final decision.
The Utility Electric Distribution Business:
During the second quarter of 1998, the CPUC issued various decisions in
which it indicated its support for competition within the electric
distribution market. We believe that these regulatory pronouncements are
not consistent with prior CPUC policy on distribution competition, including
duplicative distribution facilities. Moreover, we believe that these
pronouncements have increased substantially the uncertainty surrounding the
future role of California's electric utility distribution companies. In
addition, we believe that the CPUC made these statements without a
comprehensive examination of such fundamental issues as: (1) recovery of
electric distribution transition costs; (2) the shifting of costs among
customer classes and geographic regions; (3) the economic and environmental
impacts of distribution competition; and (4) the distribution utilities'
statutory obligation to serve.
During the third quarter of 1998, the FERC issued a decision requiring
the Utility to provide wholesale transmission service to an irrigation
district. The district requested 16 points of interconnection with the
Utility's distribution facilities in order to serve 19 customers. The
Utility believes that the requested service is equivalent to retail
wheeling. The FERC decision may further facilitate duplicate electric
distribution facilities.
At this time, we cannot predict the extent that the CPUC or the FERC will
allow the future construction of duplicative distribution facilities by
other providers or the impact that future duplicative distribution
facilities and increased competition will have on the Utility's future
financial condition and results of operations.
The Utility Gas Business:
In March 1998, the Utility implemented a CPUC-approved accord with a broad
coalition of customer groups and industry participants that adopted market-
oriented policies in the Utility's natural gas transmission business. The
accord unbundled the Utility's gas transmission and storage services from
its distribution services and established gas transmission and storage rates
for the period March 1998 through December 2002. In addition, the accord
increases the opportunity for the Utility's residential and small commercial
(core) customers to purchase gas from competing suppliers.
In January 1998, the CPUC opened a rulemaking proceeding to further
expand market-oriented policies in California's gas industry. Policies
under consideration included the additional unbundling of services,
streamlining regulation for noncompetitive services, mitigating the
potential for anti-competitive behavior, and establishing appropriate
consumer protections. As required by the CPUC, several gas utilities,
including the Utility, and other interested parties filed reports with the
CPUC about gas market conditions. On August 6, 1998, the CPUC issued an
order requiring the utilities to file cost and rate undbundling applications
with the CPUC by February 26, 1999.
However, in August 1998, the California Legislature passed and the
Governor signed Senate Bill (SB) 1602, which requires the CPUC to submit to
the Legislature any findings or recommendations that would direct further
natural gas industry restructuring for core customers. SB 1602 also
prohibits the CPUC from enacting any such decision prior to January 1, 2000.
In light of this new law, the CPUC issued an order on October 8, 1998,
stating that it would not enforce its order from August 6, 1998. The CPUC
plans to prepare a report for the Legislature identifying its proposed long
term market structure for the natural gas industry after hearings scheduled
to be held in January 1999. In concurrence with the new law, the CPUC will
not adopt a final market structure policy before January 1, 2000. At this
time, we cannot predict the outcome of these proceedings and their impact on
our financial position and results of operations.
Unregulated Business Operations:
We provide a wide range of integrated energy products and services designed
to take advantage of the competitive energy marketplace throughout the
United States. Through our unregulated subsidiaries, we: (1) provide gas
transmission services in Texas and the Pacific Northwest; (2) develop,
build, operate, own, and manage electric generation facilities across the
country; (3) provide customers nationwide with services to manage and make
more efficient their energy consumption; and (4) purchase and resell energy
commodities and related financial instruments. In providing integrated
energy products and services, we continually evaluate the composition of our
assets.
PG&E Corporation:
PG&E Corporation became the holding company of the Utility in 1997. At that
time, we transferred the unregulated subsidiaries of the Utility to PG&E
Corporation. A condition of the CPUC's approval of the holding company
formation was that the CPUC's Office of Ratepayer Advocates (ORA) oversee an
audit of transactions between the Utility and its affiliates for the period
1994 to 1996. The audit report, completed in November 1997, was critical of
the Utility's affiliate transaction internal controls and compliance. The
auditors recommended imposing conditions affecting the financing and
business composition of the Corporation.
In April 1998, the Utility filed testimony with the CPUC opposing the
recommended conditions. Hearings were completed in September 1998 to
determine if the additional recommended conditions should be imposed on PG&E
Corporation. We expect a final CPUC decision in early 1999.
If the CPUC imposed the recommended financial conditions on the
Corporation without modification, then such conditions could have an adverse
impact on future results of operations.
ACQUISITIONS AND SALES:
In July 1998, the Corporation sold its Australian energy holdings to Duke
Energy International, LLP (DEI), a subsidiary of Duke Energy Corporation.
The assets, located in the southeast corner of the Australian state of
Queensland, include a 627-kilometer gas pipeline, pipeline operations, and
trading and marketing operations.
The sale to DEI represents a premium on the price in local currency of
the Corporation's 1996 investment in the assets. However, the transaction
resulted in a non-recurring charge of $.06 per share in the second quarter,
primarily due to the 22 percent currency devaluation of the Australian
dollar against the U.S. dollar during the past two years.
On September 1, 1998, the Corporation, through its subsidiary U.S.
Generating Company (USGen), completed the acquisition of a portfolio of
electric generating assets and power supply contracts from the New England
Electric System (NEES) for $1.59 billion, plus $85 million for early
retirement and severance costs previously committed to by NEES. The
acquisition has been accounted for using the purchase method of accounting.
Accordingly, the purchase price has been preliminarily allocated to the
assets purchased and the liabilities assumed based upon the fair values at
the date of acquisition.
Including fuel and other inventories and transaction costs, the
Corporation's financing requirements total approximately $1.8 billion,
funded through $1.3 billion of USGen debt and a $425 million equity
contribution. The net purchase price has been preliminarily allocated as
follows: (1) Property, plant, and equipment of $2.3 billion; (2) Receivable
for support payments of $0.8 billion; and (3) Contractual obligations of
$1.3 billion. The assets include hydroelectric, coal, oil, and natural gas
generation facilities with a combined generating capacity of 4,000 megawatts
(MW). In addition, USGen assumed 25 multi-year power purchase agreements
representing an additional 800 MW of production capacity. USGen entered
into agreements with NEES as part of the acquisition, which: (1) provide
that NEES shall make support payments over the next ten years to USGen for
the purchase power agreements; and (2) require that USGen provide
electricity to NEES under contracts that expire over the next four to twelve
years.
The Corporation acquired NEES's generating facilities and power supply
contracts in anticipation of deregulation of the electric industry in
several New England states. In Massachusetts, electric industry
restructuring legislation opened retail competition in the electric
generation business on March 1, 1998. However, a referendum requesting
voters to approve the continuation of this legislation in Massachusetts is
on the November 1998 ballot. If the voters vote to reject the legislation,
then the restructuring legislation in Massachusetts will be repealed. The
Corporation does not expect that a repeal of the Massachusetts legislation,
which relates primarily to the retail electricity market, would have a
material impact on its results of operations or financial position.
YEAR 2000:
The Year 2000 issue exists for the Corporation because many software and
embedded systems use only two digits to identify a year in a date field, and
were developed without considering the impact of the upcoming change in the
century. Some of these systems are critical to our operations and business
processes and might fail or function incorrectly if not repaired or replaced
with Year 2000 ready products. By "ready", we mean that the system is
remediated so that it will perform its essential functions. We define
"software" as both computer programming that has been developed by the
Corporation for its own purposes ("in-house software") and that purchased
from vendors ("vendor software"). "Embedded systems" refers to both
computing hardware and other electronic monitoring, communications, and
control systems that have microprocessors within them.
Our Year 2000 project focuses on those systems that are critical to our
business. By "critical" we mean those systems the failure of which would
directly and adversely affect our ability to generate or deliver our
products and services or otherwise affect revenues, safety, or reliability
for such a period of time as to lead to unrecoverable consequences. For
these critical systems, we have adopted a phased approach to address Year
2000 issues. The primary phases include: (1) an enterprise-wide inventory,
in which systems critical to our business are identified; (2) assessment, in
which critical systems are evaluated as to their readiness to operate after
December 31, 1999; (3) remediation, in which critical systems that are not
Year 2000 ready are made so, either through modifications or replacement;
(4) testing, in which remediation is validated by checking the ability of
the critical system to operate within the Year 2000 time frame; and
(5) certification, in which systems are formally acknowledged to be Year
2000 ready, and acceptable for production or operation.
Our Year 2000 project is proceeding generally on schedule. For in-house
and vendor software, we have completed the inventory phase and have
identified approximately 1,000 critical systems. Additional software that
requires Year 2000 remediation may be discovered as we continue with the
assessment, remediation, and testing phases. We estimate that roughly 40
percent of identified, critical, in-house software has been remediated, with
completion of remediation of remaining in-house software scheduled for the
end of 1998. We estimate that roughly 10 percent of critical vendor
software has been remediated and received. Our corporate milestone for
receipt of all remediated vendor software is March 1999. We plan to finish
testing remediated in-house and vendor software by May 1999 and expect to
complete the certification phase for software by July 1999.
We also have completed the inventory of all embedded systems, although
additional embedded items that require Year 2000 repair or replacement may
be discovered as we continue with the assessment, remediation, and testing
phases. Remediation of all critical embedded systems is planned to be
completed by April 1999. We expect to finish testing of these remediated
systems by August 1999, and plan to complete the certification phase for
embedded systems by October 1999.
We are testing remediated software and embedded systems both for ability
to handle Year 2000 dates, including appropriate leap year calculations, and
to assure that code repair has not affected the base functionality of the
code. Software and embedded systems are tested individually and where
judged appropriate will be tested in an integrated manner with other
systems, with dates and data advanced and aged to simulate Year 2000
operations. Testing, by its nature, however, cannot comprehensively address
all future combinations of dates and events. Therefore, some uncertainty
will remain after testing is completed as to the ability of code to process
future dates, as well as the ability of remediated systems to work in an
integrated fashion with other systems.
We also depend upon external parties, including customers, suppliers,
business partners, gas and electric system operators, government agencies,
and financial institutions, to reliably deliver their products and services.
To the extent that any of these parties experience Year 2000 problems in
their systems, the demand for and the reliability of our services may be
adversely affected. The primary phases we have undertaken to deal with
external parties are: (1) inventory, in which critical business
relationships are identified; (2) action planning, in which we develop a
series of actions and a time frame for monitoring expected external party
compliance status; (3) assessment, in which the likelihood of external party
Year 2000 readiness is periodically evaluated; and (4) contingency planning,
in which appropriate plans are made to be ready to deal with the potential
failure of an external party to be Year 2000 ready.
We have completed our inventory of external contacts and have identified
more than 1,000 critical relationships. We soon will complete the action-
planning phase for each of these entities. Additional critical
relationships may be entered into or discovered as we continue. Assessment
of Year 2000 readiness of these external parties will continue through 1999.
We expect to complete contingency plans for each of these critical business
relationships by July 1999.
We plan to develop contingency plans for our critical software or
embedded systems for which we determine Year 2000 repair or replacement is
substantially at risk. For example, if the schedule for repairing or
replacing a non-compliant system lags and cannot be re-scheduled to meet
certain milestones, then we expect to begin an appropriate contingency
planning process. These contingency plans would be implemented as
necessary, if a remediated system does not become available by the date it
is needed. In addition, as described above, we plan to develop contingency
plans for the potential failure of critical external parties to fully
address their Year 2000 issues.
We also recognize that, given the complex interaction of today's
computing and communication systems, we cannot be certain that all of our
efforts to have all critical systems Year 2000 ready will be successful.
Therefore, irrespective of the progress of the Year 2000 project, we are
preparing contingency plans for each subsidiary and essential business
function. These plans will take into account the possibility of multiple
system failures, both internal and external, due to Year 2000 effects.
These subsidiary and essential business function contingency plans will
build on existing emergency and business restoration plans. Although no
definitive list of scenarios for this planning has yet been developed, the
events that we considered for planning purposes include increased frequency
and duration of interruptions of the power, computing, financial, and
communications infrastructure. We expect to complete first drafts of these
subsidiary and essential business function contingency plans by the
beginning of 1999. We anticipate testing and revision of these plans
throughout 1999.
Due to the speculative nature of contingency planning, it is uncertain
whether our contingency plans to address failure of external parties or
internal systems will be sufficient to reduce the risk of material impacts
on our operations due to Year 2000 problems.
The Corporation currently is revising and refining its procedures for
tracking and reporting costs associated with its Year 2000 effort. From
1997 through September 1998, we have spent approximately $80 million to
assess and remediate Year 2000 problems. About $60 million of this cost was
for software systems that we replaced for business purposes generally
unrelated to addressing Year 2000 readiness, but whose schedule we advanced
to meet Year 2000 requirements. The replacement costs for these accelerated
systems were capitalized.
We estimate that our future costs to address Year 2000 issues will be
approximately $180 million. About $50 million of these remaining Year 2000
costs will be capitalized because they relate to the purchase and
installation of systems for general business purposes and the remaining $130
million will be expensed. As we continue to assess our systems and as the
remediation, testing, and certification phases of our compliance effort
progress, our estimated costs may change. Further, we expect to incur costs
in the year 2000 and beyond to remediate and replace less critical software
and embedded systems. We do not believe that the incremental cost of
addressing Year 2000 issues will have a material impact on the Corporation's
or the Utility's financial position or results of operation.
The Corporation's current schedule is subject to change, depending on
developments that may arise through further assessment of our systems, and
through the remediation and testing phases of our compliance effort.
Further, our current schedule is partially dependent on the efforts of third
parties, including vendors, suppliers, and customers. Delays by third
parties may cause our schedule to change. There also are risks associated
with loss of or inability to locate critical personnel to remediate and
return to service the identified critical systems. We may fail to locate
all systems critical to our business processes that require remediation. A
combination of businesses and government entities may fail to be Year 2000
ready, which may lead to a substantial reduction in a demand for our energy
services.
Based on our current schedule for the completion of Year 2000 tasks, we
believe our plan is adequate to secure Year 2000 readiness of our critical
systems. We expect our remediation efforts and those of external parties to
be largely successful. Nevertheless, achieving Year 2000 readiness is
subject to various risks and uncertainties, many of which are noted above.
We are not able to predict all the factors that could cause actual results
to differ materially from our current expectations as to our Year 2000
readiness. If we, or third parties with whom we have significant business
relationships, fail to achieve Year 2000 readiness with respect to critical
systems, there could be a material adverse impact on the Utility's and the
Corporation's financial position, results of operations, and cash flows.
LIQUIDITY AND CAPITAL RESOURCES:
Sources of Capital:
- -------------------
The Corporation funds capital requirements from cash provided by operations
and, to the extent necessary, external financing. The Corporation's policy
is to finance its assets with a capital structure that minimizes financing
costs, maintains financial flexibility and, with regard to the Utility,
complies with regulatory guidelines. Based on cash provided from operations
and the Corporation's capital requirements, the Corporation may repurchase
equity and long-term debt in order to manage the overall balance of its
capital structure.
During the nine-month period ended September 30, 1998, the Corporation
issued $52 million of common stock, primarily through the Dividend
Reinvestment Plan and the Stock Option Plan. Also during the nine-month
period ended September 30, 1998, the Corporation paid dividends of $355
million and declared dividends of $343 million. The Utility paid dividends
of $315 million to PG&E Corporation during the nine-month period ended
September 30, 1998. In October 1998, the Utility declared dividends of $100
million payable to the Corporation in October. In October 1998, the
Corporation declared the fourth quarter regular common dividend of $.30 per
share payable January 15, 1999, to shareholders of record on December 15,
1998.
As of December 31, 1997, the Board of Directors had authorized the
repurchase of up to $1.7 billion of our common stock on the open market or
in negotiated transactions. As part of this authorization, in January 1998,
the Corporation repurchased in a specific transaction 37 million shares of
common stock. In connection with this transaction, the Corporation entered
into a forward contract with an investment institution. The Corporation
settled the forward contract in September 1998. There are no more
outstanding shares to be repurchased under this program.
The Corporation maintains a $500 million revolving credit facility,
which expires in 2002. In August 1997, we entered into an additional
$500 million 364-day credit facility, which expires on November 29, 1998.
The Corporation may extend the facilities annually for additional one-year
periods upon agreement with the banks. These credit facilities are used for
general corporate purposes and support our commercial paper program. The
Corporation had $469 million of commercial paper outstanding at September
30, 1998.
On September 1, 1998, USGen entered into a $1.675 billion revolving
credit facility. The facility is to be used for general corporate purposes.
The total amount outstanding at September 30, 1998, under the facility, was
$540 million in eurodollar loans and $788 million in short-term commercial
paper.
At September 30, 1998, GTT had $130 million of outstanding short-term
bank borrowings related to separate short-term credit facilities. The
borrowings are unrestricted as to use.
In July 1998, the Utility repurchased $800 million of its common stock
from PG&E Corporation, in addition to its $800 million common stock
repurchase from PG&E Corporation in April 1998.
The Utility's long-term debt matured, redeemed, or repurchased during the
nine-month period ended September 30, 1998, amounted to $962 million. Of
this amount: (1) $249 million related to the Utility's redemption of its 8
percent mortgage bonds due October 1, 2025; (2) $252 million related to the
Utility's repurchase of its other mortgage bonds; and (3) $397 million
related to the maturity of the Utility's 5 3/8 percent mortgage bonds. The
remaining $64 million related primarily to the other scheduled maturity of
long-term debt. Also, PG&E Funding retired $193 million of the rate
reduction bonds during the nine-month period ended September 30, 1998.
In January 1998, the Utility redeemed its Series 7.44 percent preferred
stock with a face value of $65 million. In July 1998, the Utility redeemed
its Series 6-7/8 percent preferred stock with a face value of $43 million.
The Utility maintains a $1 billion revolving credit facility, which
expires in 2002. The Utility may extend the facility annually for
additional one-year periods upon agreement with the banks. There were no
borrowings under this credit facility at September 30, 1998.
Utility Cost of Capital:
- ------------------------
The CPUC authorized a return on rate base for the Utility's gas and electric
distribution assets for 1998 of 9.17 percent. The authorized 1998 cost of
common equity is 11.20 percent, which is lower than the 11.60 percent
authorized for 1997.
As discussed above, in Transition Cost Recovery, the CPUC separately
reduced the authorized return on common equity (ROE) on our Utility's
hydroelectric and geothermal generation assets to 90 percent of the
Utility's 1997 adopted cost of debt, or 6.77 percent. The Utility believes
that this reduction is inappropriate and has sought a rehearing of this
decision.
On May 8, 1998, the Utility filed its 1999 Cost of Capital Application
with the CPUC. The Utility requested a return on common equity of 12.1
percent and an overall return on rate base of 9.53 percent for its gas and
electric distribution operations. The Utility did not request a change in
its currently authorized capital structure of 46.2 percent debt, 5.8 percent
preferred equity, and 48 percent common equity.
On August 10, 1998, the CPUC's ORA filed its testimony recommending a ROE
of 8.64 percent for electric distribution operations and a ROE of 9.32
percent for gas distribution operations. ORA's recommended ROEs result in
recommended overall returns on rate base for electric and gas distribution
operations of 7.85 percent and 8.17 percent, respectively. If adopted by
the CPUC, then ORA's recommendation would result in decreases for 1999
electric and gas distribution revenues of $162 million and $38 million,
respectively, as compared to revenues based upon ROE currently authorized by
the CPUC.
The ORA's ROE recommendation for electric distribution operations is due
to its perception of the changing economic conditions in the past year, and
its perceived reduction in business risk for electric distribution
operations as compared to the formerly integrated generation, transmission,
and distribution operations. The ORA also believes that the CPUC's method
of adjusting the cost of capital annually based on incremental changes in
economic factors has led to what the ORA believes have been inflated
authorized returns in recent years.
To the extent the actual electric and gas rate bases adopted by the CPUC
in the GRC proceeding are less than the rate bases proposed by the Utility,
the estimated 1999 revenue reductions from the lower ROEs recommended by the
ORA in the cost of capital proceeding would be less. We expect the CPUC to
adopt a final decision in the cost of capital proceeding in February 1999,
and a final decision in the GRC proceeding in March 1999.
1999 General Rate Case (GRC):
- -----------------------------
In December 1997, the Utility filed its 1999 GRC application with the CPUC.
During the GRC process, the CPUC examines the Utility's non-fuel related
costs to determine the amount it can charge customers. The Utility has
requested an increase in authorized revenues, to be effective January 1,
1999, of $572 million in electric base revenues and an increase of $460
million in gas base revenues over authorized 1998 revenues.
On June 26, 1998, the ORA provided their revenue requirement calculation,
which supplements ORA's June 8, 1998, report on the 1999 GRC proceeding.
The ORA recommended a decrease of $86 million in electric base revenues and
an increase in gas base revenues of $91 million over the Utility's 1998
authorized base revenues.
Hearings for the GRC before an administrative law judge took place from
August 24, 1998, through October 16, 1998. The administrative law judge
considers testimony and other evidence from many parties, including the ORA.
The Utility expects the CPUC to issue a proposed decision by the
administrative law judge in February 1999. The CPUC may accept all, part,
or none of the ORA's recommendations. We cannot predict the amount of base
revenue increase or decrease the CPUC ultimately will approve. In the event
of an adverse decision by the CPUC, and if the Utility is unable to lower
expenses to conform to the base revenue amounts adopted by the CPUC while
maintaining safety and system reliability standards, the ability of the
Utility to earn its authorized rate of return for the years 1999 through
2001 would be adversely affected.
The CPUC permitted the Utility to submit a plan for establishing interim
rates, effective January 1, 1999, to cover the period between that date and
the date the CPUC issues its decision. The CPUC plans to issue a decision
on interim rates in December 1998.
The 1999 GRC will not affect the authorized revenues for electric and gas
transmission services or for gas storage services. The Utility's authorized
revenues for each of these services are determined in other proceedings.
Environmental Matters:
- ----------------------
We are subject to laws and regulations established to both improve and
maintain the quality of the environment. Where our properties contain
hazardous substances, these laws and regulations require us to remove or
remedy the effect on the environment.
At September 30, 1998, the Utility expects to spend $282 million for
clean-up costs at identified sites over the next 30 years. If other
responsible parties fail to pay or expected outcomes change, then these
costs may be as much as $486 million. Of the $282 million, the Utility has
recovered $97 million and expects to recover $162 million in future rates.
Additionally, the Utility is seeking recovery of its costs from insurance
carriers and from other third parties. Further, as discussed above, the
Utility will retain the pre-closing remediation liability associated with
divested generation facilities. (See Note 4 of Notes to Consolidated
Financial Statements.)
Legal Matters:
- --------------
In the normal course of business, both the Utility and the Corporation are
named as parties in a number of claims and lawsuits. See Part II, Item 1,
Legal Proceedings and Note 4 to the Consolidated Financial Statements for
further discussion of significant pending legal matters.
Risk Management Activities:
- ---------------------------
In the first quarter of 1998, the CPUC granted approval for the Utility to
use financial instruments to manage price volatility of gas purchased for
our Utility electric generation portfolio. The approval limits the
Utility's outstanding financial instruments to $200 million, with downward
adjustments occurring as the Utility divests its fossil-fueled generation
plants (see Utility Generation Divestiture, above). Authority to use these
risk management instruments ceases upon the full divestiture of fossil-
fueled generation plants or at the end of the current electric rate freeze
(see Rate Freeze and Rate Reduction, above), whichever comes first.
In the second quarter of 1998, the CPUC granted conditional authority to
the Utility to use natural gas-based financial instruments to manage the
impact of natural gas prices on the cost of electricity purchased pursuant
to existing power purchase contracts. Under the authority granted in the
CPUC decision, no natural gas-based financial instruments shall have an
expiration date later than December 31, 2001. Further, if the rate freeze
ends before December 31, 2001, the Utility shall net any outstanding
financial instrument contracts through equal and opposite contracts, within
a reasonable amount of time. Also during the second quarter, the Utility
filed an application with the CPUC to use natural gas-based financial
instruments to manage price and revenue risks associated with its natural
gas transmission and storage assets. See Note 1 for additional discussion
of risk management activities. The Utility currently does not use financial
instruments to manage price risk.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PG&E Corporation's and Pacific Gas and Electric Company's primary market
risk results from changes in energy prices and interest rates. We engage in
price risk management activities for both non-hedging and hedging purposes.
Additionally, we may engage in hedging activities using futures, options,
and swaps to hedge the impact of market fluctuations on energy commodity
prices, interest rates, and foreign currencies. (See Risk Management
Activities, above.)
PART II. OTHER INFORMATION
---------------------------
Item 1. Legal Proceedings
-----------------
A. Texas Franchise Fee Litigation
As previously disclosed in PG&E Corporation and Pacific Gas and Electric
Company's Annual Report on Form 10-K for the fiscal year ended December 31,
1997, and in a Current Report on Form 8-K dated August 25, 1998, in
connection with PG&E Corporation's acquisition of Valero Energy Corporation
(Valero), now known as PG&E Gas Transmission, Texas Corporation (GTT),
various PG&E Corporation entities (formerly Valero entities) are defendants
in eight lawsuits pending in several Texas state courts involving claims
related to, among other things, the payment of franchise fees or street use
fees to Texas cities and municipalities and the conduct of the defendants.
On June 15, 1998, a jury trial began in the 92nd State District Court,
Hidalgo County, Texas, in the case of the City of Edinburg (City) v. Rio
Grande Valley Gas Co. (RGVG), Valero Energy Corporation (now known as GTT),
Valero Transmission Company (now known as PG&E Texas Pipeline Company),
Valero Natural Gas Company (now known as PG&E Texas Natural Gas Company),
Reata Industrial Gas Company (now known as PG&E Energy Trading Holdings
Corporation), Valero Transmission, L.P. (now known as PG&E Texas Pipeline,
L.P.), and Reata Industrial Gas, L.P. (now known as PG&E Reata Energy,
L.P.), and Southern Union Gas Company and certain affiliates (SU). At
issue, among other things, in the case is the franchise agreement entered
into between RGVG, the local gas distribution company, and the City on
October 1, 1985, to permit RGVG to sell gas and construct, maintain, own,
and operate gas pipelines in city streets. At the time of entering into the
franchise agreement, RGVG was a wholly owned subsidiary of Valero. Valero
(now GTT) sold RGVG to Southern Union Gas Company on September 30, 1993.
On August 14, 1998, a jury returned a verdict in favor of the City and
awarded damages in the approximate aggregate amount of $9.8 million, plus
attorneys' fees of approximately $3.5 million, against GTT, SU and various
affiliates. The jury found that RGVG committed fraud in connection with
entering into the franchise agreement and further found that RGVG failed to
comply with the franchise agreement with respect to payments due under the
agreement. The jury also found that RGVG transferred the rights,
privileges, and duties required to be performed by RGVG under the agreement
without the express written consent of the City. The jury found that GTT
and various GTT subsidiaries tortiously interfered with the franchise
agreement and that the City did not consent to the location of GTT's
pipelines on public easements within the City. Also, the jury found that
GTT was responsible for the conduct of RGVG from October 1, 1985 (the date
the franchise agreement was entered into) until September 30, 1993 (the date
GTT, then known as Valero, sold RGVG to Southern Union).
The jury refused to award punitive damages against the GTT defendants. A
hearing on the plaintiff's motion for entry of judgment has been scheduled
for December 1, 1998, after which the court will enter a judgment. At the
hearing, the court may provide guidance as to how the damages and attorneys'
fees of approximately $13.3 million will be apportioned among the parties.
If an adverse judgment is entered, GTT and its various subsidiaries intend
to appeal the judgment.
The Corporation believes the ultimate outcome of the Texas franchise fees
cases described above will not have a material adverse impact on its
financial position or results of operation.
Item 5. Other Information
-----------------
A. Ratio of Earnings to Fixed Charges and Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
Pacific Gas and Electric Company's earnings to fixed charges ratio for the
nine months ended September 30, 1998 was 3.01. Pacific Gas and Electric
Company's earnings to combined fixed charges and preferred stock dividends
ratio for the nine months ended September 30, 1998 was 2.84. The statement
of the foregoing ratios, together with the statements of the computation of
the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included
herein for the purpose of incorporating such information and exhibits into
Registration Statement Nos. 33-62488, 33-64136, 33-50707 and 33-61959,
relating to Pacific Gas and Electric Company's various classes of debt and
first preferred stock outstanding.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 10.1 PG&E Corporation Deferred Compensation Plan for
Officers, as amended and restated July 22, 1998
Exhibit 10.2 PG&E Corporation Deferred Compensation Plan for
Directors, as amended and restated July 22, 1998
Exhibit 10.3 PG&E Corporation Executive Stock Ownership Program,
as amended and restated July 22, 1998
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
Exhibit 27.1 Financial Data Schedule for the quarter ended
September 30, 1998 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
September 30, 1998 for Pacific Gas and Electric
Company
(b) Reports on Form 8-K during the third quarter of 1998 and
through the date hereof (1):
1. July 10, 1998
Item 5. Other Events
A. Electric Industry Restructuring
1. California Voter Initiative
2. Divestiture
B. Pacific Gas and Electric Company's General Rate Case
Proceeding
C. Sale of Australian Assets
2. July 16, 1998
Item 5. Other Events
A. Second Quarter 1998 Consolidated Earnings(unaudited)
3. August 25, 1998
Item 5. Other Events
A. Pacific Gas and Electric Company's 1999 Cost of Capital Proceeding
B. Texas Franchise Fee Litigation
4. October 21, 1998
Item 5. Other Events
A. Third Quarter 1998 Consolidated Earnings
(unaudited)
(1) Unless otherwise noted, all Reports on Form 8-K were filed under
both Commission File Number 1-12609 (PG&E Corporation) and Commission
File Number 1-2348(Pacific Gas and Electric Company)
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrants have duly caused this report to be signed on their
behalf by the undersigned thereunto duly authorized.
PG&E CORPORATION
and
PACIFIC GAS AND ELECTRIC COMPANY
CHRISTOPHER P. JOHNS
November 2, 1998 By
-----------------------
CHRISTOPHER P. JOHNS
Vice President and Controller
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company
Exhibit Index
Exhibit No. Description of Exhibit
10.1 PG&E Corporation Deferred Compensation Plan for Officers,
as amended and restated July 22, 1998
10.2 PG&E Corporation Deferred Compensation Plan for
Directors, as amended and restated July 22, 1998
10.3 PG&E Corporation Executive Stock Ownership Program, as
amended and restated July 22, 1998
11 Computation of Earnings Per Common Share
12.1 Computation of Ratio of Earnings to Fixed Charges for
Pacific Gas and Electric Company
12.2 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas and
Electric Company
27.1 Financial Data Schedule for the quarter ended September
30, 1998 for PG&E Corporation
27.2 Financial Data Schedule for the quarter ended September
30, 1998 for Pacific Gas and Electric Company