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, 1999
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 6, 1999:
PG&E Corporation 383,979,721 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
<PAGE>
PG&E CORPORATION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 1999
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME........................1
CONSOLIDATED BALANCE SHEET..............................2
STATEMENT OF CONSOLIDATED CASH FLOWS ...................4
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME........................5
CONDSOLIDATED BALANCE SHEET.............................6
STATEMENT OF CONSOLIDATED CASH FLOWS....................8
NOTE 1: GENERAL...........................................9
NOTE 2: CALIFORNIA ELECTRIC INDUSTRY RESTRUCTURING........9
NOTE 3: PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS..16
NOTE 4: ACQUISITIONS AND SALES...........................17
NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED DEBENTURES...........18
NOTE 6: COMMITMENTS AND CONTINGENCIES....................18
NOTE 7: SEGMENT INFORMATION..............................21
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS. ....................23
COMPETITIVE AND REGULATORY ENVIRONMENT....................24
The Competitive Environment in the Evolving
Energy Industry........................................24
California Industry Restructuring......................25
New England Electricity Market.........................32
Regulatory Matters.....................................33
RESULTS OF OPERATIONS.....................................37
LIQUIDITY AND FINANCIAL RESOURCES.........................43
ENVIRONMENTAL MATTERS.....................................45
YEAR 2000.................................................46
PRICE RISK MANAGEMENT ACTIVITIES..........................47
LEGAL MATTERS.............................................48
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................49
PART II. OTHER INFORMATION
ITEM 4. LEGAL PROCEEDINGS.........................................50
ITEM 5. OTHER INFORMATION.........................................50
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................51
SIGNATURE..........................................................52
<PAGE>
PART I. FINANCIAL INFORMATION
ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
PG&E CORPORATION
STATEMENT OF CONSOLIDATED INCOME
(in millions, except per share amounts)
<CAPTION>
Three months ended Nine months ended
September 30, September 30,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operating Revenues
Utility $ 2,587 $ 2,563 $ 6,905 $ 6,706
Energy commodities and services 3,793 2,744 9,552 7,741
-------- -------- -------- --------
Total operating revenues 6,380 5,307 16,457 14,447
-------- -------- -------- --------
Operating Expenses
Cost of energy for utility 864 724 2,183 1,982
Cost of energy commodities and services 3,556 2,560 8,842 7,184
Operating and maintenance, net 788 759 2,360 2,330
Depreciation, amortization, and decommissioning 680 737 1,684 1,403
-------- -------- -------- --------
Total operating expenses 5,888 4,780 15,069 12,899
-------- -------- -------- --------
Operating Income 492 527 1,388 1,548
Interest expense, net (191) (193) (584) (586)
Other income, net 20 18 80 25
-------- -------- -------- --------
Income Before Income Taxes 321 352 884 987
Income taxes 138 142 365 464
-------- -------- -------- --------
Net Income $ 183 $ 210 $ 519 $ 523
======== ======== ======== ========
Weighted Average Common Shares
Outstanding 367 382 369 382
Earnings Per Common Share, Basic $ .50 $ .55 $ 1.41 $ 1.37
Earnings Per Common Share, Diluted $ .50 $ .55 $ 1.40 $ 1.37
Dividends Declared Per Common Share $ .30 $ .30 $ .90 $ .90
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
CONSOLIDATED BALANCE SHEET (in millions)
<CAPTION>
Balance at September 30, December 31,
1999 1998
------------- ------------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 269 $ 286
Short-term investments 37 55
Accounts receivable
Customers, net 1,631 1,856
Energy marketing 770 507
Price Risk Management 707 1,416
Inventories and prepayments 799 835
-------- --------
Total current assets 4,213 4,955
Property, Plant, and Equipment
Utility 22,783 23,996
Non-utility
Electric generation 1,906 1,967
Gas transmission 3,391 3,347
Construction work in progress 425 407
Other 177 127
-------- --------
Total property, plant, and equipment (at original cost) 28,682 29,844
Accumulated depreciation and decommissioning (11,179) (12,026)
-------- --------
Net property, plant, and equipment 17,503 17,818
Other Noncurrent Assets
Regulatory assets 5,363 6,347
Nuclear decommissioning funds 1,225 1,172
Other 3,182 2,942
-------- --------
Total noncurrent assets 9,770 10,461
-------- --------
TOTAL ASSETS $ 31,486 $ 33,234
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
CONSOLIDATED BALANCE SHEET (in millions)
<CAPTION>
Balance at September 30, December 31,
1999 1998
------------ ------------
<S> <C> <C>
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 962 $ 1,644
Current portion of long-term debt 537 338
Current portion of rate reduction bonds 286 290
Accounts payable
Trade creditors 777 1,001
Other 540 443
Regulatory balancing accounts 934 79
Energy marketing 660 381
Accrued taxes 412 103
Price risk management 725 1,412
Other 1,017 1,064
-------- --------
Total current liabilities 6,850 6,755
Noncurrent Liabilities
Long-term debt 6,845 7,422
Rate reduction bonds 2,108 2,321
Deferred income taxes 3,223 3,861
Deferred tax credits 241 283
Other 3,669 3,746
-------- --------
Total noncurrent liabilities 16,086 17,633
Preferred Stock of Subsidiaries 480 480
Utility Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures 300 300
Common Stockholders' Equity
Common stock, no par value, authorized 800,000,000 shares,
issued 384,033,110 and 382,603,564 shares 5,904 5,862
Common stock held by subsidiary, at cost, 16,600,000 shares (531) -
Reinvested earnings 2,397 2,204
-------- --------
Total common stockholders' equity 7,770 8,066
Commitments and Contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 31,486 $ 33,234
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PG&E CORPORATION
STATEMENT OF CONSOLIDATED CASH FLOWS (in millions)
<CAPTION>
For the nine months ended September 30, 1999 1998
---------- ----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 519 $ 523
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization and decommissioning 1,684 1,403
Deferred income taxes and tax credits-net (652) (309)
Other deferred charges and noncurrent liabilities (729) (682)
Loss on sale of assets - 22
Net effect of changes in operating assets
and liabilities:
Accounts receivable - trade (225) 704
Regulatory balancing accounts payable 855 618
Inventories and prepayments 36 (45)
Price risk management assets and liabilities, net 22 2
Accounts payable - trade (224) (118)
Accrued taxes 309 501
Other working capital 64 (101)
Other-net 346 (3)
--------- ---------
Net cash provided by operating activities 2,005 2,515
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (1,058) (1,262)
Proceeds from the sale of assets 1,014 58
Other-net 108 (190)
--------- ---------
Net cash used by investing activities 64 (1,394)
--------- ---------
Cash Flows From Financing Activities
Net (repayments) borrowings under credit facilities (682) 507
Long-term debt issued - 137
Long-term debt matured, redeemed, or repurchased (611) (1,295)
Preferred stock redeemed or repurchased - (105)
Common stock issued 44 48
Common stock repurchased (534) (1,159)
Dividends paid (335) (377)
Other-net 14 37
--------- ---------
Net cash used by financing activities (2,104) (2,207)
--------- ---------
Net Change in Cash and Cash Equivalents (35) (1,086)
Cash and Cash Equivalents at January 1 341 1,397
--------- ---------
Cash and Cash Equivalents at September 30 $ 306 $ 311
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 518 $ 527
Income taxes (net of refunds) 589 264
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED INCOME (in millions)
<CAPTION>
Three months ended Nine months ended
September 30, September 30,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Electric utility $ 2,189 $ 2,226 $ 5,550 $ 5,496
Gas utility 398 337 1,355 1,210
-------- -------- -------- --------
Total operating revenues 2,587 2,563 6,905 6,706
-------- -------- -------- --------
Operating Expenses
Cost of electric energy 746 650 1,681 1,577
Cost of gas 118 74 502 405
Operating and maintenance, net 615 632 1,849 2,002
Depreciation, amortization, and decommissioning 622 695 1,513 1,292
-------- -------- -------- --------
Total operating expenses 2,101 2,051 5,545 5,276
-------- -------- -------- --------
Operating Income 486 512 1,360 1,430
Interest expense, net (148) (154) (450) (475)
Other income, net 8 15 30 79
-------- -------- -------- -------
Income Before Income Taxes 346 373 940 1,034
Income taxes 161 168 424 480
-------- -------- -------- -------
Net Income 185 205 516 554
Preferred dividend requirement 6 6 18 21
-------- -------- -------- -------
Income Available for Common Stock $ 179 $ 199 $ 498 $ 533
======== ======== ======== =======
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET (in millions)
<CAPTION>
Balance at
September 30, December 31,
1999 1998
------------ -----------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents $ 84 $ 73
Short-term investments 20 17
Accounts receivable
Customers, net 1,255 1,383
Related parties 5 14
Inventories
Fuel oil and nuclear fuel 163 187
Gas stored underground 152 130
Materials and supplies 163 159
Prepayments 36 50
--------- ---------
Total current assets 1,878 2,013
Property, Plant, and Equipment
Electric 15,592 16,924
Gas 7,191 7,072
Construction work in progress 202 273
--------- ---------
Total property, plant, and equipment (at original cost) 22,985 24,269
Accumulated depreciation and decommissioning (10,409) (11,397)
--------- ---------
Net property, plant, and equipment 12,576 12,872
Other Noncurrent Assets
Regulatory assets 5,306 6,288
Nuclear decommissioning funds 1,225 1,172
Other 756 605
-------- --------
Total noncurrent assets 7,287 8,065
-------- --------
TOTAL ASSETS $ 21,741 $ 22,950
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEET (in millions)
<CAPTION>
Balance at
September 30, December 31,
1999 1998
------------ -----------
<S> <C> <C>
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings $ 77 $ 668
Current portion of long-term debt 443 260
Current portion of rate reduction bonds 286 290
Accounts payable
Trade creditors 618 718
Related parties 50 60
Regulatory balancing accounts 934 79
Other 355 374
Accrued taxes 233 2
Deferred income taxes 26 3
Other 564 558
-------- -------
Total current liabilities 3,586 3,012
Noncurrent Liabilities
Long-term debt 5,025 5,444
Rate reduction bonds 2,108 2,321
Deferred income taxes 2,280 3,060
Deferred tax credits 241 283
Other 2,233 2,045
-------- -------
Total noncurrent liabilities 11,887 13,153
Preferred Stock With Mandatory Redemption Provisions
6.30% and 6.57%, outstanding 5,500,000 shares, due 2002-2009 137 137
Company Obligated Mandatorily Redeemable Preferred Securities of
Trust Holding Solely Utility Subordinated Debentures
7.90%, 12,000,000 shares due 2025 300 300
Stockholders' Equity
Preferred stock without mandatory redemption provisions
Nonredeemable - 5% to 6%, outstanding 5,784,825 shares 145 145
Redeemable - 4.36% to 7.04%, outstanding 5,973,456 shares 142 142
Common stock, $5 par value, authorized 800,000,000 shares,
issued and outstanding 321,314,760 and 341,353,455 1,607 1,707
Additional paid in capital 1,971 2,094
Reinvested earnings 1,966 2,260
-------- --------
Total stockholders' equity 5,831 6,348
Commitments and Contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 21,741 $ 22,950
======== ========
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
<TABLE>
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONSOLIDATED CASH FLOWS (in millions)
<CAPTION>
For the nine months ended September 30, 1999 1998
----------- -----------
<S> <C> <C>
Cash Flows From Operating Activities
Net income $ 516 $ 554
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization, and decommissioning 1,513 1,292
Deferred income taxes and tax credits-net (799) (297)
Other deferred charges and noncurrent liabilities (496) 162
Net effect of changes in operating assets
and liabilities:
Accounts receivable 128 339
Regulatory balancing accounts payable 855 269
Inventories and prepayments 12 7
Accounts payable - trade (100) 116
Accrued taxes 231 265
Other working capital (10) 24
Other-net 76 24
--------- ---------
Net cash provided by operating activities 1,926 2,755
--------- ---------
Cash Flows From Investing Activities
Capital expenditures (848) (963)
Proceeds from sale of assets 1,014 -
Other-net 21 297
--------- ---------
Net cash provided (used) by investing activities 187 (666)
--------- ---------
Cash Flows From Financing Activities
Net repayments under credit facilities (591) -
Long-term debt matured, redeemed, or repurchased (474) (1,175)
Preferred stock redeemed or repurchased - (107)
Common stock repurchased (725) (1,600)
Dividends paid (309) (337)
--------- ---------
Net cash used by financing activities (2,099) (3,219)
--------- ---------
Net Change in Cash and Cash Equivalents 14 (1,130)
Cash and Cash Equivalents at January 1 90 1,223
--------- ---------
Cash and Cash Equivalents at September 30 $ 104 $ 93
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 363 $ 401
Income taxes (net of refunds) 852 587
<FN>
The accompanying Notes to the Consolidated Financial Statements are an integral part of this
statement.
</TABLE>
<PAGE>
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: GENERAL
Basis of Presentation:
- ----------------------
This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation
and Pacific Gas and Electric Company (the Utility), a regulated subsidiary of
PG&E Corporation. The Notes to Consolidated Financial Statements apply to
both PG&E Corporation and the Utility. PG&E Corporation's consolidated
financial statements include the accounts of PG&E Corporation and its wholly
owned and controlled subsidiaries, including the Utility (collectively, the
Corporation). The Utility's consolidated financial statements include its
accounts as well as those of its wholly owned and controlled subsidiaries.
The Utility's financial position and results of operations are the
principal factors affecting the Corporation's consolidated financial position
and results of operations. This quarterly report should be read in conjunction
with the Corporation's and the Utility's Consolidated Financial Statements and
Notes to Consolidated Financial Statements incorporated by reference in their
combined 1998 Annual Report on Form 10-K, and the Corporation's and the
Utility's other reports filed with the Securities and Exchange Commission
since their 1998 Form 10-K was filed.
PG&E Corporation and the Utility believe that the accompanying statements
reflect all adjustments that are necessary to present a fair statement of the
consolidated financial position and results of operations for the interim
periods. All material adjustments are of a normal recurring nature unless
otherwise disclosed in this Form 10-Q. All significant intercompany
transactions have been eliminated from the consolidated financial statements.
Certain amounts in the prior year's consolidated financial statements have
been reclassified to conform to the 1999 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.
NOTE 2: CALIFORNIA ELECTRIC INDUSTRY RESTRUCTURING
In 1998, California became one of the first states in the country to
implement electric industry restructuring legislation and establish a
competitive market for electric generation. In a transition to a competitive
market, the restructuring legislation recognized that market-based revenues
may not be sufficient to recover (that is, collect from customers) all of the
Utility's generation costs. The restructuring legislation provides the
California investor-owned utilities the opportunity to recover such
uneconomic generation costs (called transition costs) until the earlier of
December 31, 2001, or when the utilities have recovered their authorized
transition costs as determined by the California Public Utilities Commission
(CPUC). The period during which transition costs may be recovered is called
the transition period. The legislation permits certain transition costs to
be recovered after the transition period.
<PAGE>
The restructuring legislation has four principal elements: (1) the
establishment of a competitive market framework, (2) an electric rate freeze
and rate reduction, (3) the recovery of transition costs, and (4) divestiture
of utility-owned generation facilities. Each element is discussed below.
Competitive Market Framework:
- -----------------------------
To create a competitive generation market, a Power Exchange (PX) and an
Independent System Operator (ISO) began operating on March 31, 1998. During
the transition period, the Utility is required to bid or schedule into the PX
and ISO markets all of the electricity generated by its power plants and
electricity acquired under contractual agreements with unregulated
generators. Also during the transition period, the Utility is required to
buy from the PX all electricity needed to provide service to retail customers
that continue to choose the Utility as their electricity supplier. The ISO
schedules delivery of electricity for all market participants. The Utility
continues to own and maintain a portion of the transmission system, but the
ISO controls the operation of the system.
Among other changes to the ISO and PX market structure, on October 1,
1999, the ISO increased the price limitation on acceptable bids for
electricity and ancillary services (standby power and miscellaneous services)
from $250 per megawatt hour to $750 per megawatt hour. The increased price
limitation may increase the price volatility of energy and ancillary services
purchased in ISO and PX markets. The ISO's authority to impose price
limitations on acceptable bids will expire on November 15, 1999, unless
extended by the Federal Energy Regulatory Commission (FERC). The Utility's
cost of energy is recovered from retail customers under the terms of the
restructuring plan.
For the three- and nine-month periods ended September 30, 1999 and 1998,
the cost of electric energy for the Utility, reflected on the Statement of
Consolidated Income, is comprised of the cost of PX purchases, ancillary
services purchased from the ISO, cost of transmission, and the cost of
Utility generation, net of sales to the PX as follows:
<TABLE>
<CAPTION>
Three months ended Nine months ended
September 30, September 30,
1999 1998 1999 1998
-------- -------- -------- --------
<S> <C> <C> <C> <C>
(in millions)
Cost of electric generation $ 409 $ 562 $ 1,177 $ 1,526
Cost of purchases from the PX 384 380 710 490
Cost of ancillary services 170 179 391 265
Proceeds from sales to the PX (217) (471) (597) (704)
-------- -------- -------- --------
Cost of electric energy $ 746 $ 650 $ 1,681 $ 1,577
-------- -------- -------- --------
</TABLE>
Rate Freeze and Rate Reduction:
- -------------------------------
Legislation required an electric rate freeze and an electric rate reduction
to extend throughout the transition period. The Utility has held rates for
its larger customers at 1996 levels, and it will hold their rates at that
level until the end of the transition period. On January 1, 1998, the
Utility reduced electric rates for its residential and small commercial
customers by 10 percent from 1996 levels, and it will hold their rates at
that level until the end of the transition period. Collectively, these
actions are called a rate freeze.
<PAGE>
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion of its transition costs with the proceeds from rate reduction bonds.
The bonds allow for the rate reduction by lowering the carrying cost on a
portion of the transition costs and by deferring recovery of a portion of
these transition costs until after the transition period. During the rate
freeze, the rate reduction bond debt service will not increase the Utility
customers' electric rates. If the transition period ends before December 31,
2001, the Utility will be obligated to return a portion of the bond proceeds
to customers. The timing and exact amount of such portion, if any, has not
yet been determined.
The frozen rates include a component for transition cost recovery.
Transition costs are being recovered from all Utility distribution customers
through a nonbypassable charge regardless of the customer's choice of
electricity supplier. As the customer charge for transition costs is
nonbypassable, the Utility believes that the availability of choice to its
customers will not have a material impact on its ability to recover
transition costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public
purpose programs, nuclear decommissioning, and rate reduction bond debt
service. To the extent the revenues from frozen rates exceed authorized
Utility costs, the remaining revenues constitute the competitive transition
charge (CTC), which recovers the transition costs. These CTC revenues are
subject to seasonal fluctuations in the Utility's sales volumes and certain
other factors.
Transition Cost Recovery:
- -------------------------
Market-based revenues through sales to the PX may not be sufficient to
recover all of the Utility's generation costs. Under the California
restructuring legislation, the Utility has the opportunity to recover its
transition costs until the earlier of December 31, 2001, or when the Utility
has recovered its authorized transition costs as determined by the CPUC,
although certain transition costs can be recovered after the transition
period. At the conclusion of the transition period, the Utility will be at
risk to recover any of its remaining generation costs through market-based
revenues.
Transition costs consist of: (1) above-market sunk costs (costs associated
with Utility-owned generation assets that are fixed and unavoidable and
included in the Utility customers' electric rates) and future costs, such as
costs related to removal of Utility-owned generation facilities, (2) costs
associated with the Utility's long-term contracts to purchase power at above-
market prices from qualifying facilities and other power suppliers, and (3)
generation-related regulatory assets and obligations. (In general,
regulatory assets are expenses deferred in the current or prior periods, to
be included in rates in subsequent periods.)
Above-market sunk costs result when the book value of a facility is in
excess of its market value. Conversely, below-market sunk costs result when
the market value of a facility is in excess of its 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
<PAGE>
cost. The below-market portion of these costs will reduce other unrecovered
transition costs. These above- and below-market sunk costs are related to
generating facilities that are classified as either non-nuclear or nuclear
sunk costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until a market
valuation process (through appraisal, sale, or other valuation method) is
completed for each of its non-nuclear generation facilities. Several of
these valuations occurred in 1997 and 1998, when the Utility agreed to sell
seven of its electric generation plants to third parties. The total market
value of these facilities resulted in sales proceeds that exceeded the book
value and therefore has reduced the amount of transition costs remaining to
be recovered. The remainder of the valuation process is expected to be
completed by December 31, 2001. The Utility's remaining non-nuclear
generation facilities consist primarily of its hydroelectric generation
system. On September 30, 1999, the Utility filed an application with the
CPUC to determine the market value of its hydroelectric generating facilities
and related assets through an open, competitive auction. The Utility plans
to use an auction process similar to the one previously approved by the CPUC
and successfully used in the sale of the Utility's fossil and geothermal
plants. If the market value of the Utility's hydroelectric facilities is
determined based upon any method other than a sale of the facilities to a
third party, a material charge to Utility earnings could result. Any excess
of market value over book value would be used to reduce other transition
costs. (See Generation Divestiture below.)
Nuclear generation sunk costs were determined separately through a CPUC
proceeding and were subject to a final verification audit that was completed
in August 1998. The audit of the Utility's Diablo Canyon Nuclear Power Plant
(Diablo Canyon) accounts at December 31, 1996, 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. The independent accounting firm also issued an agreed-upon special
procedures report, requested by the CPUC, that questioned $200 million of the
$3.3 billion sunk costs. The CPUC will review any proposed adjustments to
Diablo Canyon's recoverable costs that resulted from the report. At this
time, the Utility cannot predict what actions, if any, the CPUC may take
regarding the audit report.
Costs associated with the Utility's long-term contracts to purchase
electric power at above-market prices are included as transition costs. Over
the remaining life of these contracts the Utility estimates that it will
purchase 322 million megawatt-hours of electric power. To the extent that
the individual contract prices are above the market price, the Utility is
collecting the difference between the contract price and the market price
from customers, as a transition cost, over the term of the contract. The
contracts expire at various dates through 2028. The total amount of the
above-market costs under long-term contracts will be based on several
variables, including the capacity factors of the related generating
facilities and future market prices for electricity. During the nine-month
period ended September 30, 1999, the average price paid per kilowatt-hour
(kWh) under the Utility's long-term contracts for electric power was 6.4
cents per kWh. The average cost of electric energy for energy purchased at
market rates from the PX for the nine-month period ended September 30, 1999,
was 3.3 cents per kWh.
<PAGE>
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At September
30, 1999, the Utility's generation-related net regulatory assets totaled $4.4
billion.
Most transition costs can be recovered until December 31, 2001. This
recovery period is significantly shorter than the recovery period of the
generation assets prior to restructuring and is referred to as accelerated
recovery. Accordingly, the Utility is amortizing its transition costs,
including most generation-related regulatory assets over the transition
period. During the transition period, the Utility is receiving a reduced
return on common equity for all of its generation assets, including those
generation assets reclassified to regulatory assets. The reduced return on
common equity is 6.77 percent.
Certain transition costs can be recovered through a non-bypassable charge
to distribution customers after the transition period. These costs include:
(1) certain employee-related transition costs, (2) above-market payments
under existing long-term contracts to purchase power, discussed above, (3) up
to $95 million of transition costs after the transition period to the extent
that the recovery of such costs during the transition period was displaced by
the recovery of electric industry restructuring implementation costs, and (4)
transition costs financed by the rate reduction bonds. Transition costs
financed by the issuance of rate reduction bonds are expected to be recovered
over the term of the bonds. In addition, the Utility's nuclear
decommissioning costs are being recovered through a CPUC-authorized charge,
which will extend until sufficient funds exist to decommission the nuclear
facility. During the rate freeze the charge for these costs will not
increase the Utility customers' electric rates. Excluding these exceptions,
the Utility will write off any transition costs not recovered during the
transition period.
Revenues provided for the recovery of most non-nuclear transition costs
are based upon the acceleration of such costs within the transition period.
For Diablo Canyon transition costs, revenues provided for transition cost
recovery are based on: (1) an established incremental cost incentive price
(ICIP) per kWh generated by Diablo Canyon to recover certain ongoing costs
and capital additions, and (2) the accelerated recovery of the investment in
Diablo Canyon from a period ending in 2016 to a five-year period ending
December 31, 2001. On September 1, 1999, a proposed decision was issued by
an administrative law judge of the CPUC that, among other matters, would
terminate the Utility's ability to continue to recover revenues related to
Diablo Canyon based on the ICIP once the Utility has completed recovery of
all Utility-owned generation related transition costs. The Utility had
argued that it should be entitled to rely on the CPUC decision establishing
the ICIP mechanism which stated that the ICIP mechanism would continue
through December 31, 2001. The proposed decision is subject to comment by
the parties and change by the full CPUC before a final decision is issued.
The CPUC is expected to issue a final decision in the near future.
The Utility is amortizing its eligible transition costs, including
generation-related regulatory assets, over the transition period in
conjunction with the available CTC revenues. Effective January 1, 1998, the
Utility started collecting these eligible transition costs through the
nonbypassable CTC. For the nine months ended September 30, 1999, regulatory
assets related to electric utility restructuring decreased by $954 million,
which reflects the recovery of eligible transition costs.
<PAGE>
During the transition period, the CPUC reviews the Utility's compliance
with the accounting methods established in the CPUC's decisions governing
transition cost recovery and the amount of transition costs requested for
recovery. The CPUC is currently reviewing non-nuclear transition costs
amortized during the first six months of 1998.
Generation Divestiture:
- -----------------------
In 1998, the Utility completed the sale of three fossil-fueled generation
plants for $501 million. These three fossil-fueled plants had a combined
book value at the time of the sale of $346 million and had a combined
capacity of 2,645 megawatts (MW).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled
plants had a combined book value of $256 million and had a combined capacity
of 3,065 MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
The Utility has retained a liability for required environmental
remediation related to any pre-closing soil or groundwater contamination at
the plants which it has sold. The Utility records its estimated liability
for the retained environmental remediation obligation as part of the
determination of the gain or loss on the sale of each plant.
The gains from the sale of the fossil-fueled generation plants were used
to offset other transition costs. Likewise, the loss from the sale of the
complex of geothermal generation facilities is being recovered as a
transition cost.
On September 30, 1999, the Utility filed an application with the CPUC to
determine the market value of its hydroelectric generating facilities and
related assets through an open, competitive auction. The Utility proposes to
use an auction process similar to the one previously approved by the CPUC and
successfully used in the sale of the Utility's fossil and geothermal plants.
Under the process proposed in the application, another subsidiary of PG&E
Corporation, PG&E Generating Company (PG&EGen), would be permitted to
participate in the auction on the same basis as other bidders.
The proposed auction process is estimated to take at least 21 weeks after
CPUC approval of the process. The CPUC proceedings related to the proposed
auction are likely to be contentious and involve many interested parties.
The sale of the hydroelectric facilities would be subject to certain
conditions, including the approval of the FERC and other agencies to the
transfer or re-issuance of various permits and licenses. In addition, FERC
must approve assignment of the Utility's Reliability Must Run Contract with
the ISO for any facility subject to such contract. Under the proposed
purchase and sale agreement, the CPUC's approval of the proposed sale on
terms acceptable to the Utility in its sole discretion is also a condition
precedent to the closing of any sale.
<PAGE>
The CPUC may approve the Utility's auction application or rule that some
other method of valuation is appropriate.
At September 30, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.8 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory
assets recoverable as transition costs. The value of the hydroelectric
assets is expected to exceed their book value by a material amount. Any
excess of market value over the $0.8 billion book value would be used to
reduce transition costs, including the remaining $0.5 billion of regulatory
assets related to the hydroelectric generation assets. If the market value
of the hydroelectric generation assets is determined by any method other than
a sale of the assets to a third party, or if the winning bidder for any of
the auctioned assets is PG&EGen, a material charge to Utility earnings could
result. The timing and nature of any such charge is dependent upon the
valuation method and procedure adopted, and the method of implementation.
While transfer or sale to an affiliated entity such as PG&EGen may result in
a material charge to income, PG&E Corporation does not believe sales of any
generation facilities to a third party will have a material impact on its
results of operations.
If the value of the hydroelectric generation assets is significantly
higher than the book value, the transition period could end before December
31, 2001.
Financial Impact of Electric Industry Restructuring:
- ----------------------------------------------------
The Utility's ability to continue recovering its transition costs will be
dependent on several factors, including: (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 determined value of the Utility's hydroelectric 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 and transmission costs are increased or decreased, and (7) the
market price of electricity. Given the current evaluation of these factors,
PG&E Corporation believes that the Utility will recover its transition costs
under the terms of the approved transition plan. However, a change in one or
more of these factors could affect the probability of recovery of transition
costs and result in a material charge.
<PAGE>
NOTE 3: PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
The following table is a summary of the contract or notional amounts and
maturities of PG&E Corporation's contracts used for non-hedging activities
related to commodity price risk management as of September 30, 1999. Short
and long positions pertaining to derivative contracts used for hedging
activities as of September 30, 1999, are immaterial.
Maximum
Natural Gas, Electricity, Purchase Sale Term in
and Natural Gas Liquids Contracts (Long) (Short) Years
- ---------------------------------------------------------------------
(billions of MMBtu equivalents (1))
Non-Hedging Activities
Swaps 3.18 3.14 7
Options 1.13 0.99 5
Futures 0.29 0.30 2
Forward Contracts 1.95 1.59 12
(1) One MMBtu is equal to one million British thermal units. PG&E
Corporation's electric power contracts, measured in megawatts, were converted
to MMBtu equivalents using a conversion factor of 10 MMBtu's per 1 megawatt-
hour. PG&E Corporation's natural gas liquids contracts were converted to
MMBtu equivalents using an appropriate conversion factor for each type of
natural gas liquids product.
Volumes shown for swaps represent notional volumes that are used to
calculate amounts due under the agreements and do not represent volumes
exchanged. Moreover, notional amounts are indicative only of the volume of
activity and are not a measure of market risk.
PG&E Corporation's net gains (losses) on swaps, options, futures, and
forward contracts held during the three- and nine-month periods ended
September 30, 1999 are as follows:
For the three For the nine
months ended months ended
September 30, 1999 September 30, 1999
- -----------------------------------------------------------------------------
(in millions)
Swaps $ (7) $ (5)
Options 30 (5)
Futures (3) (23)
Forward contracts (35) 60
------ ------
Net gain (loss) $ (15) $ 27
<PAGE>
The following table discloses the estimated fair values of price risk
management assets and liabilities as of September 30, 1999. The ending and
average fair values and associated carrying amounts of derivative contracts
used for hedging purposes are not material as of September 30, 1999.
Average Ending
Fair Value Fair Value
- --------------------------------------------------------------------------
(in millions)
Assets
Non-Hedging Activities
Swaps $ 743 $ 301
Options 109 116
Futures 207 106
Forward Contracts 685 506
------ ------
Total $1,744 $1,029
Noncurrent portion 322
Current portion $ 707
Liabilities
Non-Hedging Activities
Swaps $ 685 $ 278
Options 116 79
Futures 235 122
Forward Contracts 587 412
------ ------
Total $1,623 $ 891
Noncurrent portion 166
Current portion $ 725
The credit exposure of the five largest counterparties comprised
approximately $245 million of the total credit exposure associated with
financial instruments used to manage price risk. Counterparties considered to
be investment grade or higher comprise 71 percent of the total credit
exposure.
NOTE 4: ACQUISITIONS AND SALES
In September 1998, PG&E Corporation, through its indirect subsidiary USGen New
England, Inc. (USGenNE), completed the acquisition of a portfolio of electric
generating assets and power supply contracts from the New England Electric
System (NEES). The acquisition has been accounted for using the purchase
method of accounting. Accordingly, the purchase price has been allocated to
the assets purchased and the liabilities assumed based upon an assessment of
the fair values at the date of acquisition.
Including fuel and other inventories and transaction costs, PG&E
Corporation's financing requirements for this acquisition were approximately
<PAGE>
$1.8 billion, funded through an aggregate of $1.3 billion PG&E Generating
Company (PG&EGen) and USGenNE debt and a $425 million equity contribution
from PG&E Corporation. (On June 1, 1999, U.S. Generating Company changed its
name to PG&E Generating Company). The net purchase price has been allocated
as follows: (1) electric generating assets of $2.3 billion classified as
property, plant, and equipment; (2) receivable for support payments of $0.8
billion; and (3) contractual obligations of $1.3 billion classified as
current liabilities and other noncurrent liabilities. The assets include
hydroelectric, coal, oil, and natural gas generation facilities with a
combined generating capacity of 4,000 MW. In addition, USGenNE assumed 23
multi-year power-purchase agreements representing an additional 800 MW of
production capacity. USGenNE 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 USGenNE for the purchase power agreements; and (2)
require that USGenNE provide electricity to NEES under contracts that expire
over the next six to eleven years.
NOTE 5: 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 6: 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 this insurance, if a nuclear generating facility suffers a loss due to
a prolonged accidental outage, 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. The Utility has
secondary financial protection which provides an additional $9.5 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 it has been or may be a potentially responsible party under the
<PAGE>
Comprehensive Environmental Response, Compensation and Liability Act and
similar state environmental laws. These sites include former manufactured
gas plant sites, power plant sites, and sites used by it for the storage or
disposal of potentially hazardous materials. Under federal and California
laws, it may be responsible for remediation of hazardous substances, even if
it 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) current 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 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, 1999, of $296 million for hazardous waste remediation costs at
identified sites, including divested fossil-fueled power plants.
Of the $296 million liability, discussed above, the Utility has recovered
$137 million and expects to recover $127 million in future rates.
Additionally, the Utility is mitigating its costs by obtaining recovery of
its costs from insurance carriers and from other third parties as
appropriate.
Environmental remediation at identified sites may be as much as $481
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 outcomes
change.
Further, as discussed in Generation Divestiture above, the Utility will
retain the pre-closing remediation liability associated with divested
generation facilities.
PG&E 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 California state
courts. The suits seek an unspecified amount of compensatory and punitive
<PAGE>
damages for alleged personal injuries resulting from alleged exposure to
chromium in the vicinity of the Utility's gas compressor stations at Hinkley,
Kettleman, and Topock, California. Currently, there are claims pending on
behalf of approximately 1,650 individuals.
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.
PG&E Corporation believes that the ultimate outcome of these matters 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 (PG&E GTT), PG&E GTT
succeeded to the litigation described below.
PG&E GTT and various of its affiliates are defendants in at least two
class action suits and four 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 1998, a jury trial was held in the separate suit brought by the City of
Edinburg (the City). This suit involved, among other things, a particular
franchise agreement entered into by a former subsidiary of PG&E GTT (now
owned by Southern Union Gas Company (SU)) and the City and certain conduct of
the defendants.
On December 1, 1998, based on the jury verdict, the court entered a
judgment in the City's favor, and awarded damages of $5.3 million, and
attorneys' fees of up to $3.5 million plus interest. The court found that
various PG&E GTT and SU defendants were jointly and severally liable for $3.3
million of the damages and all the attorneys' fees. Certain PG&E GTT
subsidiaries were found solely liable for $1.4 million of the damages. The
court did not clearly indicate the extent to which the PG&E GTT defendants
could be found liable for the remaining damages. The PG&E GTT defendants are
in the process of appealing the judgment.
PG&E Corporation believes that the ultimate outcome of these matters
could have a material adverse impact on its financial position or its
results of operations.
The Utility's 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 costs to determine
the amount the Utility may charge customers. The Utility has requested
distribution revenue increases to maintain and improve gas and electric
<PAGE>
distribution reliability, safety, and customer service. The requested
revenues, as updated, include an increase of $445 million in electric base
revenues and an increase of $377 million in gas base revenues over authorized
1998 revenues. The Office of Ratepayer Advocates (ORA) branch of the CPUC
has recommended a decrease of $80 million in electric revenues and an
increase of $104 million in gas base revenues. Recommendations by the ORA do
not represent the positions of the CPUC.
In December 1998, the CPUC issued a decision on interim rate relief in the
GRC. The decision granted the Utility's request to increase its electric
revenues by $445 million and its gas revenues by $377 million on an interim
basis pending a decision in the GRC. The decision allows the Utility to
reflect the revenue increases, resulting from the Utility request, in
regulatory assets recorded under regulatory adjustment mechanisms approved by
the CPUC. However, the decision does not increase any electric or gas rates
billed to customers on an interim basis.
The Utility's 1999 earnings are based on the authorized amount of
revenues in effect during 1998 and do not include any portion of the
requested revenue increase. When a final decision in the GRC is issued by
the CPUC, the Utility's regulatory assets and net income will be adjusted to
reflect the revenue approved in the final decision. Any such adjustment
could have a material impact on the Utility's and PG&E Corporation's results
of operations.
NOTE 7: SEGMENT INFORMATION
PG&E Corporation has identified five reporting operating segments. The
Utility is one reportable operating segment and the other four are part of
PG&E Corporation's National Energy Group. These five reportable operating
segments provide different products and services and are subject to different
forms of regulation or jurisdictions. PG&E Corporation's reportable segments
are described below.
Utility: PG&E Corporation's Northern and Central California energy utility
subsidiary, Pacific Gas and Electric Company, provides natural gas and
electric service to one of every 20 Americans.
National Energy Group: PG&E Corporation's National Energy Group consists
of PG&E Generating Company (PG&EGen) which develops, builds, operates, owns,
and manages power generation facilities that serve wholesale and industrial
customers; PG&E Gas Transmission (PG&E GT) which owns and operates
approximately 9,000 miles of natural gas pipelines, approximately 500 miles
of natural gas liquids pipelines, a storage facility, and natural gas
processing plants in the Pacific Northwest (PG&E GT NW) and Texas (PG&E GTT);
PG&E Energy Trading (PG&E ET) which purchases and sells energy commodities
and provides risk management services to customers in major North American
markets, including, serving PG&E Corporation's other non-utility businesses,
unaffiliated utilities, marketers, municipalities, and large end-use
customers; and PG&E Energy Services (PG&E ES) which provides competitively
priced electricity, natural gas, and related services to industrial,
commercial, and institutional customers.
Segment information for the three- and nine-month periods ended September
30, 1999 and 1998, respectively, were as follows:
<PAGE>
<TABLE>
<CAPTION>
National Energy Group
----------------------------------------------------
PG&E GT Elimi-
---------------- nations &
Utility PG&EGen NW Texas PG&E ET PG&E ES Other (1) Total
------- ------- ------- ------- ------- ------- ------- -------
(in millions)
For the three-month period ended:
- ---------------------------------
September 30, 1999
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $ 2,584 $ 273 $ 42 $ 161 $3,151 $ 163 $ 6 $ 6,380
Intersegment revenues 3 2 14 16 339 3 (377) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 2,587 275 56 177 3,490 166 (371) 6,380
Net income 179 19 18 (7) (17) (12) 3 183
September 30, 1998
Operating revenues $ 2,562 $ 151 $ 45 $ 397 $2,053 $ 99 $ - $ 5,307
Intersegment revenues 1 4 13 56 103 9 (186) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 2,563 155 58 453 2,156 108 (186) 5,307
Net income 199 30 16 (22) - (15) 2 210
For the nine-month period ended:
- --------------------------------
September 30, 1999
Operating revenues $ 6,898 $ 814 $ 127 $ 871 $7,314 $ 432 $ 1 $16,457
Intersegment revenues 7 4 39 99 831 11 (991) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 6,905 818 166 970 8,145 443 (990) 16,457
Net income 498 70 46 (39) (19) (34) (3) 519
Total assets at
September 30, 1999 21,741 3,858 1,162 2,548 2,195 186 (204) 31,486
September 30, 1998
Operating revenues $ 6,703 $ 350 $ 139 $1,261 $5,753 $ 234 $ 7 $14,447
Intersegment revenues 3 4 38 229 240 9 (523) -
------- ------- ------- ------- ------- ------- ------- -------
Total operating
revenues 6,706 354 177 1,490 5,993 243 (516) 14,447
Net income 533 73 46 (51) - (40) (38) 523
Total assets at
September 30, 1998 22,468 4,326 1,167 2,715 2,053 177 (188) 32,718
<FN>
(1) Net income on intercompany positions recognized by segments using mark to market accounting
is eliminated. Intercompany transactions are also eliminated. Corporation overhead is charged
to each subsidiary. Corporation interest expense and taxes are allocated to the National
Energy Group.
</TABLE>
<PAGE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
PG&E Corporation (the Corporation) is an energy-based holding company
headquartered in San Francisco, California. PG&E Corporation's businesses
provide energy services throughout North America. PG&E Corporation's
Northern and Central California energy utility subsidiary, Pacific Gas and
Electric Company (the Utility), provides natural gas and electric service to
one of every 20 Americans. PG&E Corporation's four other businesses, known
as the National Energy Group, provide a wide range of energy products and
services through its wholesale and retail business operations.
The National Energy Group consists of PG&E Generating Company (PG&EGen),
formerly known as U.S. Generating Company, which develops, builds, operates,
owns, and manages power generation facilities that serve wholesale and
industrial customers; PG&E Gas Transmission (PG&E GT) which owns and operates
approximately 9,000 miles of natural gas pipelines, approximately 500 miles
of natural gas liquids pipelines, a storage facility, and natural gas
processing plants in the Pacific Northwest (PG&E GT NW) and Texas (PG&E GTT);
PG&E Energy Trading (PG&E ET) which purchases and sells energy commodities
and provides risk management services to customers in major North American
markets, including, serving PG&E Corporation's other non-utility businesses,
unaffiliated utilities, marketers, municipalities, and large end-use
customers; and PG&E Energy Services (PG&E ES) which provides competitively
priced electricity, natural gas, and related services to industrial,
commercial, and institutional customers.
This is a combined Quarterly Report on Form 10-Q of PG&E Corporation and
Pacific Gas and Electric Company. It includes separate consolidated
financial statements for each entity. The consolidated financial statements
of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility,
and PG&E Corporation's other wholly owned and controlled subsidiaries. The
consolidated financial statements of the Utility reflect the accounts of the
Utility and its wholly owned subsidiaries. This Management's Discussion and
Analysis (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 1998 Annual Report on Form 10-K and the
Corporation's and the Utility's other reports filed with the Securities and
Exchange Commission since their 1998 Form 10-K was filed.
This combined Quarterly Report on Form 10-Q, including this MD&A, contains
forward-looking statements about the future that are necessarily subject to
various risks and uncertainties. These statements are based on the beliefs
and assumptions of management which management believes are reasonable and on
information currently available to management. These forward-looking
statements are identified by words such as "estimates," "expects,"
"anticipates," "plans," "believes", "speculates", and other similar
expressions.
Factors that could cause future results to differ materially from those
expressed in or implied by the forward-looking statements or historical
results include:
- - the pace and extent of the ongoing restructuring of the electric and gas
industries across the United States;
- - operational changes related to industry restructuring, including changes in
the Utility's business processes and systems;
<PAGE>
- - the method and timing of disposition and valuation of the Utility's
hydroelectric generation assets;
- - any changes in the amount the Utility is allowed to collect (recover) from
its customers for certain costs which prove to be uneconomic under the new
competitive market (called transition costs);
- - the successful integration and performance of acquired assets;
- - our ability to successfully compete outside our traditional regulated
markets;
- - internal and external Year 2000 software and hardware issues;
- - the outcome of the Utility's various regulatory proceedings, including: the
1999 general rate case; the proposal to adopt performance based ratemaking
(PBR); the proposal to auction the Utility's hydroelectric generation assets;
the transmission rate case applications; and post-transition period
ratemaking proceedings;
- - fluctuations in commodity gas and electric prices and our ability to
successfully manage such price fluctuations; and
- - the pace and extent of competition in the California generation market and
its impact on the Utility's costs and resulting collection of transition
costs.
Although the ultimate impacts of the above factors are uncertain, these
and other factors may cause future earnings to differ materially from results
or outcomes we currently seek or expect. Each of these factors is discussed
in greater detail in this MD&A.
In this MD&A, we first discuss our competitive and regulatory environment.
We then discuss earnings and changes in our results of operations for the
three- and nine-month periods ended September 30, 1999 and 1998. Finally, we
discuss liquidity and financial resources, various uncertainties that could
affect future earnings, and our risk management activities. Our MD&A applies
to both PG&E Corporation and the Utility.
Competitive and Regulatory Environment
This section provides a discussion of the competitive environment in the
evolving energy industry, the California electric industry restructuring, the
New England electricity market, and regulatory matters.
The Competitive Environment in the Evolving Energy Industry
- -----------------------------------------------------------
Historically, energy utilities operated as regulated monopolies within
specific service territories where they were essentially the sole suppliers
of natural gas and electricity services. Under this model, the energy
utilities owned and operated all of the businesses necessary to procure,
generate, transport, and distribute energy. These services were priced on a
combined (bundled) basis, with rates charged by the energy companies designed
to include all of the costs of providing these services. Now, energy
utilities face intensifying pressures to make competitive those activities
that are not regulated monopoly services. The most significant of these
services are electricity generation and natural gas supply.
The driving forces behind these competitive pressures are customers who
believe they can obtain energy at lower unit prices and competitors who want
access to those customers. Regulators and legislators are responding to
those customers and competitors by providing more competition in the energy
industry. Regulators and legislators are requiring utilities to "unbundle"
rates (separate their various energy services and the prices of those
<PAGE>
services). This allows customers to compare unit prices of the Utility and
other providers when selecting their energy service provider.
In the natural gas industry, Federal Energy Regulatory Commission (FERC)
Order 636 required interstate pipeline companies to divide their services
into separate gas commodity sales, transportation, and storage services.
Under Order 636, interstate gas pipelines must provide transportation
service regardless of whether the customer (often a local gas distribution
company) buys the gas commodity from the pipeline.
In the electric industry, the Public Utilities Regulatory Policies Act of
1978 specifically provided that unregulated companies could become wholesale
generators of electricity and that utilities were required to purchase and
use power generated by these unregulated companies in meeting their
customers' needs. The National Energy Policy Act of 1992 was designed to
increase competition in the wholesale unregulated generation market by
requiring access to electric utility transmission systems by all wholesale
unregulated generators, sellers, and buyers of electricity. Now, an
increasing number of states throughout the country either have implemented
plans or are considering proposals to separate the generation from the
transmission and distribution of electricity through some form of electric
industry restructuring.
To date, the states, not the federal government, have taken the initiative
on electric industry restructuring at the retail level. While at least five
bills mandating deregulation of the electric industry were introduced in the
U.S. Congress over the past two years, none have been passed. As a result,
the pace, extent, and methods for restructuring the electric industry vary
widely throughout the country. For instance, as of September 30, 1999,
21 states have enacted electric industry restructuring legislation,
including California, Texas, Illinois, Pennsylvania, New Jersey,
Massachusetts, Rhode Island, and Connecticut. There also are some states
that have passed legislation precluding or significantly slowing down
deregulation. Differences in how individual states view electric industry
restructuring often relate to the existing unit cost of energy supplies
within each state. Generally, states having higher energy unit costs are
moving more quickly to deregulate energy supply markets.
Implementation of our national energy strategy depends, in part, upon the
opening of energy markets to provide customer choice of supplier. Undue
delays by states or federal legislation to deregulate the electric generation
and natural gas supply business could impact the pace of growth of our
National Energy Group.
California Industry Restructuring
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The Electric Business:
In 1998, California became one of the first states in the country to
implement electric industry restructuring. Today, many Californians may
choose to purchase their electricity from investor-owned utilities such as
Pacific Gas and Electric Company, or unregulated retail electricity suppliers
(for example, marketers, including PG&E Energy Services, brokers, and
aggregators). The restructuring contemplates that the investor-owned
utilities, including the Utility, will continue to provide distribution
services to substantially all customers within their service territories,
<PAGE>
including providing electricity to customers who choose not to be served by
another service provider.
The restructuring legislation recognized that market-based revenues may
not be sufficient to recover (that is, collect from customers) all of the
Utility's generation costs. The restructuring legislation provides the
California investor-owned utilities the opportunity to recover such
uneconomic generation costs (called transition costs) until the earlier of
December 31, 2001, or when the utilities have recovered their authorized
transition costs as determined by the California Public Utilities Commission
(CPUC). The period during which transition costs may be recovered is called
the transition period. The legislation permits certain transition costs to
be recovered after the transition period.
California electric industry restructuring legislation has four principal
elements: (1) the establishment of a competitive market framework, (2) an
electric rate freeze and rate reduction, (3) the recovery of transition
costs, and (4) divestiture of utility-owned generation facilities. Each
element is discussed below.
Competitive Market Framework: To create a competitive generation market, a
Power Exchange (PX) and an Independent System Operator (ISO) began operating
on March 31, 1998. During the transition period, the Utility is required to
bid or schedule into the PX and ISO markets all of the electricity generated
by its power plants and electricity acquired under contractual agreements
with unregulated generators. Also during the transition period, the Utility
is required to buy from the PX all electricity needed to provide service to
retail customers that continue to choose the Utility as their electricity
supplier. The ISO schedules delivery of electricity for all market
participants. The Utility continues to own and maintain a portion of the
transmission system, but the ISO controls the operation of the system.
Among other changes to the ISO and PX market structure, on October 1,
1999, the ISO increased the price limitation on acceptable bids for
electricity and ancillary services (standby power and miscellaneous services)
from $250 per megawatt-hour to $750 per megawatt-hour. The increased price
limitation may increase the price volatility of energy and ancillary services
purchased in ISO and PX markets. The ISO's authority to impose price
limitations on acceptable bids will expire on November 15, 1999, unless
extended by the FERC.
During 1998 and 1999, the Utility continued its efforts to develop and
implement changes to its business processes and systems, including the
customer information and billing system, to accommodate electric industry
restructuring. To the extent that the Utility is unable to develop and
implement such changes in a successful and timely manner, there could be an
adverse impact on the Utility's or PG&E Corporation's future results of
operations.
Rate Freeze and Rate Reduction: Legislation required an electric rate freeze
and an electric rate reduction to extend throughout the transition period.
The Utility has held rates for its larger customers at 1996 levels, and it
will hold their rates at that level until the end of the transition period.
On January 1, 1998, the Utility reduced electric rates for its residential
and small commercial customers by 10 percent from 1996 levels, and it will
hold their rates at that level until the end of the transition period.
Collectively, these actions are called a rate freeze.
<PAGE>
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion of its transition costs with the proceeds from rate reduction bonds.
The bonds allow for the rate reduction by lowering the carrying cost on a
portion of the transition costs and by deferring recovery of a portion of
these transition costs until after the transition period. During the rate
freeze, the rate reduction bond debt service will not increase the Utility
customers' electric rates. If the transition period ends before December 31,
2001, the Utility will be obligated to return a portion of the bond proceeds
to customers. The timing and exact amount of such portion, if any, has not
yet been determined.
The frozen rates include a component for transition cost recovery.
Transition costs are being recovered from all Utility distribution customers
through a nonbypassable charge regardless of the customer's choice of
electricity supplier. As the customer charge for transition costs is
nonbypassable, the Utility believes that the availability of choice to its
customers will not have a material impact on its ability to recover
transition costs.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public
purpose programs, nuclear decommissioning, and rate reduction bond debt
service. To the extent the revenues from frozen rates exceed authorized
Utility costs, the remaining revenues constitute the competitive transition
charge (CTC), which recovers the transition costs. These CTC revenues are
subject to seasonal fluctuations in the Utility's sales volumes and certain
other factors.
Transition Cost Recovery: Market-based revenues through sales to the PX may
not be sufficient to recover all of the Utility's generation costs. Under
the California restructuring legislation, the Utility has the opportunity to
recover its transition costs until the earlier of December 31, 2001, or when
the Utility has recovered its authorized transition costs as determined by
the CPUC, although certain transition costs can be recovered after the
transition period. At the conclusion of the transition period, the Utility
will be at risk to recover any of its remaining generation costs through
market-based revenues.
Transition costs consist of: (1) above-market sunk costs (costs associated
with Utility-owned generation assets that are fixed and unavoidable and
included in the Utility customers' electric rates) and future costs, such as
costs related to removal of Utility-owned generation facilities, (2) costs
associated with the Utility's long-term contracts to purchase power at above-
market prices from qualifying facilities and other power suppliers, and (3)
generation-related regulatory assets and obligations. (In general,
regulatory assets are expenses deferred in the current or prior periods, to
be included in rates in subsequent periods.)
Above-market sunk costs result when the book value of a facility is in
excess of its market value. Conversely, below-market sunk costs result when
the market value of a facility is in excess of its 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. These above- and below-market sunk costs are related to
<PAGE>
generating facilities that are classified as either non-nuclear or nuclear
sunk costs.
The Utility cannot determine the exact amount of above-market non-nuclear
sunk costs that will be recoverable as transition costs until a market
valuation process (through appraisal, sale, or other valuation method) is
completed for each of its non-nuclear generation facilities. Several of
these valuations occurred in 1997 and 1998, when the Utility agreed to sell
seven of its electric generation plants to third parties. The total market
value of these facilities resulted in sales proceeds that exceeded the book
value and therefore has reduced the amount of transition costs remaining to
be recovered. The remainder of the valuation process is expected to be
completed by December 31, 2001. The Utility's remaining non-nuclear
generation facilities consist primarily of its hydroelectric generation
system. On September 30, 1999, the Utility filed an application with the
CPUC to determine the market value of its hydroelectric generating facilities
and related assets through an open, competitive auction. The Utility plans
to use an auction process similar to the one previously approved by the CPUC
and successfully used in the sale of the Utility's fossil and geothermal
plants. If the market value of the Utility's hydroelectric facilities is
determined based upon any method other than a sale of the facilities to a
third party, a material charge to Utility earnings could result. Any excess
of market value over book value would be used to reduce other transition
costs. (See Generation Divestiture below.)
Nuclear generation sunk costs were determined separately through a CPUC
proceeding and were subject to a final verification audit that was completed
in August 1998. The audit of the Utility's Diablo Canyon Nuclear Power Plant
(Diablo Canyon) accounts at December 31, 1996, 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. The independent accounting firm also issued an agreed-upon special
procedures report, requested by the CPUC, that questioned $200 million of the
$3.3 billion sunk costs. The CPUC will review any proposed adjustments to
Diablo Canyon's recoverable costs that resulted from the report. At this
time, the Utility cannot predict what actions, if any, the CPUC may take
regarding the audit report.
Costs associated with the Utility's long-term contracts to purchase
electric power at above-market prices are included as transition costs. Over
the remaining life of these contracts the Utility estimates that it will
purchase 322 million megawatt-hours of electric power. To the extent that
the individual contract prices are above the market price, the Utility is
collecting the difference between the contract price and the market price
from customers, as a transition cost, over the term of the contract. The
contracts expire at various dates through 2028. The total amount of the
above-market costs under long-term contracts will be based on several
variables, including the capacity factors of the related generating
facilities and future market prices for electricity. During the nine-month
period ended September 30, 1999, the average price paid per kilowatt-hour
(kWh) under the Utility's long-term contracts for electric power was 6.4
cents per kWh. The average cost of electric energy for energy purchased at
market rates from the PX for the nine-month period ended September 30, 1999,
was 3.3 cents per kWh.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At September
<PAGE>
30, 1999, the Utility's generation-related net regulatory assets totaled $4.4
billion.
Most transition costs can be recovered until December 31, 2001. This
recovery period is significantly shorter than the recovery period of the
generation assets prior to restructuring and is referred to as accelerated
recovery. Accordingly, the Utility is amortizing its transition costs,
including most generation-related regulatory assets over the transition
period. During the transition period, the Utility is receiving a reduced
return on common equity for all of its generation assets, including those
generation assets reclassified to regulatory assets. The reduced return on
common equity is 6.77 percent.
Certain transition costs can be recovered through a non-bypassable charge
to distribution customers after the transition period. These costs include:
(1) certain employee-related transition costs, (2) above-market payments
under existing long-term contracts to purchase power, discussed above, (3) up
to $95 million of transition costs after the transition period to the extent
that the recovery of such costs during the transition period was displaced by
the recovery of electric industry restructuring implementation costs, and (4)
transition costs financed by the rate reduction bonds. Transition costs
financed by the issuance of rate reduction bonds are expected to be recovered
over the term of the bonds. In addition, the Utility's nuclear
decommissioning costs are being recovered through a CPUC-authorized charge,
which will extend until sufficient funds exist to decommission the nuclear
facility. During the rate freeze the charge for these costs will not
increase the Utility customers' electric rates. Excluding these exceptions,
the Utility will write off any transition costs not recovered during the
transition period.
Revenues provided for the recovery of most non-nuclear transition costs
are based upon the acceleration of such costs within the transition period.
For Diablo Canyon transition costs, revenues provided for transition cost
recovery are based on: (1) an established incremental cost incentive price
(ICIP) per kWh generated by Diablo Canyon to recover certain ongoing costs
and capital additions, and (2) the accelerated recovery of the investment in
Diablo Canyon from a period ending in 2016 to a five-year period ending
December 31, 2001. On September 1, 1999, a proposed decision was issued by
an administrative law judge of the CPUC that, among other matters, would
terminate the Utility's ability to continue to recover revenues related to
Diablo Canyon based on the ICIP once the Utility has completed recovery of
all Utility-owned generation related transition costs. The Utility had
argued that it should be entitled to rely on the CPUC decision establishing
the ICIP mechanism which stated that the ICIP mechanism would continue
through December 31, 2001. The proposed decision is subject to comment by
the parties and change by the full CPUC before a final decision is issued.
The CPUC is expected to issue a final decision in the near future.
The Utility is amortizing its eligible transition costs, including
generation-related regulatory assets, over the transition period in
conjunction with the available CTC revenues. Effective January 1, 1998, the
Utility started collecting these eligible transition costs through the
nonbypassable CTC. For the nine months ended September 30, 1999, regulatory
assets related to electric utility restructuring decreased by $954 million,
which reflects the recovery of eligible transition costs.
<PAGE>
During the transition period, the CPUC reviews the Utility's compliance
with the accounting methods established in the CPUC's decisions governing
transition cost recovery and the amount of transition costs requested for
recovery. The CPUC is currently reviewing non-nuclear transition costs
amortized during the first six months of 1998.
Generation Divestiture: In 1998, the Utility completed the sale of three
fossil-fueled generation plants for $501 million. These three fossil-fueled
plants had a combined book value at the time of the sale of $346 million and
had a combined capacity of 2,645 megawatts (MW).
On April 16, 1999, the Utility sold three other fossil-fueled generation
plants for $801 million. At the time of sale, these three fossil-fueled
plants had a combined book value of $256 million and had a combined capacity
of 3,065 MW.
On May 7, 1999, the Utility sold its complex of geothermal generation
facilities for $213 million. At the time of sale, these facilities had a
combined book value of $244 million and had a combined capacity of 1,224 MW.
The Utility has retained a liability for required environmental
remediation related to any pre-closing soil or groundwater contamination at
the plants which it has sold. The Utility records its estimated liability
for the retained environmental remediation obligation as part of the
determination of the gain or loss on the sale of each plant.
The gains from the sale of the fossil-fueled generation plants were used
to offset other transition costs. Likewise, the loss from the sale of the
complex of geothermal generation facilities is being recovered as a
transition cost.
On September 30, 1999, the Utility filed an application with the CPUC to
determine the market value of its hydroelectric generating facilities and
related assets through an open, competitive auction. The Utility proposes to
use an auction process similar to the one previously approved by the CPUC and
successfully used in the sale of the Utility's fossil and geothermal plants.
Under the process proposed in the application, another subsidiary of PG&E
Corporation, PG&EGen, would be permitted to participate in the auction on the
same basis as other bidders.
The proposed auction process is estimated to take at least 21 weeks after
CPUC approval of the process. The CPUC proceedings related to the proposed
auction are likely to be contentious and involve many interested parties.
The sale of the hydroelectric facilities would be subject to certain
conditions, including the approval of the FERC and other agencies to the
transfer or re-issuance of various permits and licenses. In addition, FERC
must approve assignment of the Utility's Reliability Must Run Contract with
the ISO for any facility subject to such contract. Under the proposed
purchase and sale agreement, the CPUC's approval of the proposed sale on
terms acceptable to the Utility in its sole discretion is also a condition
precedent to the closing of any sale.
The CPUC may approve the Utility's auction application or rule that some
other method of valuation is appropriate.
<PAGE>
At September 30, 1999, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.8 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory
assets recoverable as transition costs. The value of the hydroelectric
assets is expected to exceed their book value by a material amount. Any
excess of market value over the $0.8 billion book value would be used to
reduce transition costs, including the remaining $0.5 billion of regulatory
assets related to the hydroelectric generation assets. If the market value
of the hydroelectric generation assets is determined by any method other than
a sale of the assets to a third party, or if the winning bidder for any of
the auctioned assets is PG&EGen, a material charge to Utility earnings could
result. The timing and nature of any such charge is dependent upon the
valuation method and procedure adopted, and the method of implementation.
While transfer or sale to an affiliated entity such as PG&EGen may result in
a material charge to income, PG&E Corporation does not believe sales of any
generation facilities to a third party will have a material impact on its
results of operations.
If the value of the hydroelectric generation assets is significantly
higher than the book value, the transition period could end before December
31, 2001.
Financial Impact: The Utility's ability to continue recovering its transition
costs will be dependent on several factors including: (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 determined value of the Utility's hydroelectric
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 and transmission costs are increased or
decreased, and (7) the market price of electricity. Given the current
evaluation of these factors, PG&E Corporation believes that the Utility will
recover its transition costs under the terms of the approved transition plan.
However, a change in one or more of these factors could affect the
probability of recovery of transition costs and result in a material charge.
The Gas Business:
Restructuring of the natural gas industry on both the national and the state
level has given choices to California utility customers to meet their gas
supply needs. The Utility offers transmission, distribution, and storage
services as separate and distinct services to its noncore customers.
Customers have the opportunity to select from a menu of services offered by
the Utility and they pay only for the services that they use. Access to the
transmission system is possible for all gas marketers and shippers, as well
as noncore end-users.
The Utility's core customers can select the commodity gas supplier of
their choice. However, the Utility continues to purchase gas as a regulated
supplier for those core customers who request it, serving 3.8 million core
customers in its service territory.
The Utility's costs of purchasing gas for core customers through 2002 are
regulated by the core procurement incentive mechanism (CPIM), a form of
incentive ratemaking that provides the Utility a direct financial incentive
to procure gas and transportation services at the lowest reasonable costs by
comparing all procurement costs to an aggregate market-based benchmark. If
<PAGE>
costs fall within a range (tolerance band) around the benchmark, costs are
considered reasonable and fully recoverable from ratepayers. If procurement
costs fall outside the tolerance band, ratepayers and shareholders share
savings or costs, respectively.
Under the terms of the Gas Accord settlement agreement, approved by the
CPUC in 1997, gas transmission rates within California for the period from
March 1998 through December 2002 for the Utility's core and noncore customers
were established and regulatory protection was eliminated for variations in
noncore transmission revenues. As a result, the Utility is at risk for
variations between actual and forecasted transmission throughput volumes.
However, we do not expect these variations to have a material adverse impact
on the Utility's or our financial position or results of operations.
Rates for gas distribution services will continue to be set by the CPUC
and designed to provide the Utility an opportunity to recover its costs of
service and include a return on its investment. The regulatory mechanisms
for setting gas distribution rates are discussed below under Regulatory
Matters.
New England Electricity Market:
- -------------------------------
Certain New England states where our National Energy Group operates electric
generation facilities were, like California, among the first states in the
country to introduce electric industry restructuring. As a result of this
restructuring and certain other regulatory initiatives, the wholesale
unregulated electricity market in New England features a bid-based market and
an ISO.
In September 1998, PG&E Corporation, through its indirect subsidiary USGen
New England, Inc. (USGenNE), completed the acquisition of a portfolio of
electric generation assets and power supply contracts from New England
Electric System (NEES). The purchased assets include hydroelectric, coal,
oil, and natural gas generation facilities with a combined generating
capacity of about 4,000 MW.
Including fuel and other inventories and transaction costs, the financing
requirements for this transaction were approximately $1.8 billion, funded
through an aggregate of $1.3 billion of PG&EGen and USGenNE debt and a $425
million equity contribution from PG&E Corporation. The net purchase price
has been allocated as follows: (1) electric generating assets of $2.3
billion, (2) receivable for support payments of $0.8 billion, and (3) out of
market contractual obligations of $1.3 billion, relating to acquired power
purchase agreements, gas agreements and standard offer agreements.
As part of the New England electric industry restructuring, the local
utility companies providing service to retail customers were required to
offer Standard Offer Service (SOS) to their customers. Retail customers may
select alternative suppliers at any time. The SOS is intended to provide
customers with a price benefit (the commodity electric price offered to the
retail customer is expected to be less than the market price) for the first
several years, followed by a price disincentive that is intended to stimulate
the retail market.
Retail customers may continue to receive SOS through June 30, 2002, in New
Hampshire (subject to early termination on December 31, 2000, at the
discretion of the New Hampshire Public Service Commission), through December
<PAGE>
31, 2004, in Massachusetts, and through December 31, 2009, in Rhode Island.
However, if any customers elect to have their electricity provided by an
alternate supplier, they are precluded from going back to the SOS.
In connection with the purchase of the generation assets, we entered into
agreements to supply the electric capacity and energy requirements necessary
for NEES to meet its SOS obligations. NEES is responsible for passing on to
us the revenues generated from the SOS. USGenNE, is currently serving the
SOS electric capacity and energy requirements for NEES, except for New
Hampshire's SOS. On March 1, 1999, Constellation Power Source, Inc. assumed
this component of the SOS upon winning a competitive bidding solicitation.
Like California utilities, the New England utilities entered into
agreements with unregulated companies to provide energy and capacity at
prices that are anticipated to be in excess of market prices. We assumed
NEES' contractual rights and duties under several of these power-purchase
agreements, which in aggregate provide for 800 MW of capacity. However, NEES
will make support payments to us toward the cost of these agreements. The
support payments by NEES total $1.1 billion in the aggregate (undiscounted)
and are due in monthly installments from September 1998 through January 2008.
In certain circumstances, with our consent, NEES may make a full or partial
lump sum accelerated payment.
Initially, approximately 90 percent of the acquired operating capacity,
including capacity and energy generated by other companies and provided to us
under power-purchase agreements, is dedicated to providing services to
customers receiving SOS. To the extent that customers eligible to receive
SOS chose alternate suppliers, this percentage will decrease. As customers
choose alternate suppliers, a greater proportion of the output of the
acquired operating capacity will be subject to market prices.
Regulatory Matters:
- -------------------
The Utility is the only subsidiary with significant regulatory activity at
this time. Some of the items affecting future Utility authorized revenues
include: the 1999 general rate case, the distribution performance based
ratemaking application, FERC transmission rate cases, the CPUC's catastrophic
events memorandum account proceeding, the CPUC's gas strategy rulemaking, the
Diablo Canyon sunk costs audit, the post transition period ratemaking
proceeding, and the Electric Base Revenue Increase proceeding. These items
are discussed below. Any requested change in authorized electric revenues
resulting from any of these proceedings would not impact the Utility's
customer electric rates through the transition period because these rates are
frozen in accordance with the electric transition plan. However, the amount
of remaining revenues providing for the recovery of transition costs would be
affected.
The 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 costs to determine
the amount the Utility may charge customers. The Utility has requested
distribution revenue increases to maintain and improve gas and electric
distribution reliability, safety, and customer service. The requested
revenues, as updated, include an increase of $445 million in electric base
revenues and an increase of $377 million in gas base revenues over authorized
1998 revenues. The Office of Ratepayer Advocates (ORA) branch of the CPUC
<PAGE>
has recommended a decrease of $80 million in electric revenues and an
increase of $104 million in gas base revenues. Recommendations by the ORA do
not represent the positions of the CPUC.
In December 1998, the CPUC issued a decision on interim rate relief in the
GRC. The decision granted the Utility's request to increase its electric
distribution revenues by $445 million and its gas distribution revenues by
$377 million on an interim basis pending a decision in the GRC. The decision
allows the Utility to reflect the revenue increases, resulting from the
Utility request, in regulatory assets recorded under regulatory adjustment
mechanisms approved by the CPUC. However, the decision does not increase any
electric or gas rates billed to customers on an interim basis.
The GRC application also contained a proposal for an Attrition Rate
Adjustment (ARA) to adjust revenues in 2000 and 2001 if a Performance Based
Ratemaking (PBR) mechanism, as discussed below, is not adopted for 2000 or
2001. Since the CPUC has not issued a decision in the Utility's pending
PBR application on October 1, the Utility filed a request for revenue
increases in the 2000 ARA. The Utility's proposal would increase electric
distribution revenues by $118 million and gas distribution revenues by $23
million based on the Utility's requested revenues in its 1999 GRC.
Except for the impacts of the cost of capital decision, discussed below,
the Utility's 1999 earnings are based on the authorized amount of revenues
in effect during 1998 and do not include any portion of the requested
revenue increase. When a final decision in the GRC is issued by the CPUC,
the Utility's regulatory assets and net income will be adjusted to reflect
the revenues approved in the final decision. Any such adjustment could have
a material impact on the Utility's and PG&E Corporation's results of
operations.
The Distribution Performance Based Ratemaking (PBR) Application:
The Utility filed an amended distribution PBR proposal with the CPUC in
February 1999. If approved as filed, the distribution PBR will determine the
Utility's gas and electric distribution revenues for the years 2000 through
2004. Under the Utility's proposal, distribution revenues for the years 2000
through 2004 would be determined by multiplying total distribution revenues
by a rate formula. The rate formula would be based principally on inflation
less a proposed productivity factor of 1.1 percent and 0.82 percent for
electric distribution and gas distribution, respectively. These productivity
factors will be fixed for the five year duration of the PBR. The Utility has
proposed different rate formulas for gas customers, small electric customers
(principally residential and commercial customers) and large electric
customers.
The proposal also includes a sharing mechanism for earnings that are
significantly above or below the authorized weighted average cost of capital.
In addition, the proposed PBR includes rewards and penalties that will depend
upon the Utility's ability to achieve performance standards for electric
distribution reliability; maintenance, repair, and replacement; customer
service; and employee safety. The procedural schedule in the PBR proceeding
has been suspended pending the issuance of a proposed decision in the
Utility's 1999 GRC proceeding. A final decision in the PBR proceeding is not
expected to be issued until mid-2000. The Utility has applied for interim
relief, which would make the final decision effective on January 1, 2000.
<PAGE>
FERC Transmission Rate Cases:
Since April 1, 1998, all electric transmission revenues are authorized by
FERC. During 1998, the FERC issued orders that put into effect various rates
to recover electric transmission costs from the Utility's former bundled rate
transmission customers. These rates are subject to refund. On April 14,
1999, the Utility filed a settlement with FERC which, if approved, allows the
Utility to recover $168 million for the period of April 1998 through October
1998, and $177 million for the period of November 1998 through May 1999. The
Utility does not expect a material impact on its financial position or
results of operations resulting from the settlement. On May 27, 1999, FERC
approved, subject to refund, the Utility's March 30, 1999, request to begin
recovering, as of May 31, 1999, $324 million annually in revenues from its
former bundled retail transmission customers. On September 1, 1999, the
Utility filed a request to increase future revenues by $46 million annually
to $370 million for its former bundled retail transmission customers. FERC
has not yet acted upon the Utility's request.
Catastrophic Events Memorandum Account Proceeding:
On September 10, 1999, PG&E Corporation entered into a Settlement Agreement
with the ORA and other parties, in a proceeding addressing the Catastrophic
Events Memorandum Account. The settlement calls for a $70 million increase
in revenues effective January 1, 2000. Of the $70 million, $59 million is
electric and $11 million is gas distribution. The increase is to compensate
the Utility for service restoration following several events beginning with
the Berkeley Hills fire of 1991 and ending with the storms of February 1998.
A CPUC decision is expected in early 2000.
The CPUC's Gas Strategy Rulemaking:
In January 1998, the CPUC opened a rulemaking proceeding to explore changes
in the natural gas industry, including the possible further unbundling of
services to promote competition, streamlining regulation for noncompetitive
services, mitigating the potential for anti-competitive behavior, and
establishing appropriate consumer protections. In 1998, the Governor of
California signed Senate Bill 1602, allowing the CPUC to investigate issues
associated with the further restructuring of natural gas services but
prohibiting the CPUC from enacting any such gas industry restructuring
decisions prior to January 1, 2000. On July 8, 1999, the CPUC issued a
decision identifying options for restructuring the natural gas industry. In
the decision, the CPUC reaffirmed the structure of the Gas Accord and stated
that it seeks to explore that market structure that maintains the utilities'
traditional role of providing fully integrated default service to core
customers while removing obstacles to competitive offering of gas commodity,
transmission, storage, balancing, and certain other services. The CPUC
requested all interested parties to try to settle various issues raised in
the decision. The CPUC closed the existing rule-making proceedings and
opened a new investigative proceeding to explore in more detail the
anticipated costs and benefits associated with the different market structure
options the CPUC has identified. The CPUC's goal is to submit a final report
to the California Legislature on gas restructuring possibly in the first
quarter of next year. On September 8, 1999, a CPUC administrative law judge
granted the parties an approximately 45-day extension to try to settle the
various issues before filing cost/benefit testimony.
<PAGE>
The Diablo Canyon Sunk Costs Audit:
In August 1998, an independent accounting firm retained by the CPUC completed
a financial verification audit of the Utility's Diablo Canyon plant accounts
as of 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 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 Utility cannot predict what actions, if any, the
CPUC may take regarding the audit report.
Post-Transition Period Ratemaking Proceeding:
In a pending proceeding, the CPUC is considering the ratemaking mechanism
under which the Utility's transition cost recovery would be completed, the
current electric rate freeze would end, and post-transition period rates would
be established, consistent with the electric industry restructuring
legislation and the Utility's transition cost recovery plan. On September 1,
1999, a proposed decision was issued by an administrative law judge in this
proceeding that, among other matters, would terminate the Utility's ability to
continue to recover revenues related to Diablo Canyon based on the incremental
cost incentive price (ICIP) once the Utility has completed recovery of all
Utility-owned generation related transition costs. The Utility had argued
that it should be entitled to rely on the CPUC decision establishing the ICIP
mechanism which stated that the ICIP mechanism would continue through December
31, 2001.
The ICIP was established effective January 1, 1997, as a performance-based
mechanism to recover Diablo Canyon's variable and other operating costs and
capital addition costs. The ICIP mechanism establishes a rate per kWh
generated by the facility based upon a fixed forecast of ongoing costs,
capital additions, and capacity factors for the period 1997 through 2001. The
fixed forecast of ICIP for 1999, 2000, and 2001 is 3.37 cents per kWh, 3.43
cents per kWh, and 3.49 cents per kWh, respectively. In contrast, the average
cost of electric energy for energy purchased at market rates from the PX for
the twelve-months ended September 30, 1999 was 3.26 cents per kWh. Further,
with the end of the transition period, the Utility will be required to begin
sharing the net benefits of operating Diablo Canyon on a fifty-fifty basis
with ratepayers. The ultimate financial impact of the end of the ICIP
mechanism will depend on when Utility-owned generation-related transition
costs are recovered and the current electric rate freeze ends, future Diablo
Canyon operating costs, future electricity prices, and other variables the
Utility is unable to predict.
The proposed decision would also prohibit the Utility from collecting after
the rate freeze any electric costs incurred during the rate freeze but not
recovered during the rate freeze, even costs that are not transition costs and
are not related to generation assets. The utimate financial impact of this
provision will depend on the amount of any electric non-transition costs that
have been incurred but not recovered as of the end of the transition period,
the timing of various regulatory proceedings, future electicity prices, other
future costs, and other variables the Utility is unable to predict. PG&E
Corporation believes that this prohibition would be illegal if implemented
and PG&E Corporation would vigorously challenge it if adopted by the CPUC.
<PAGE>
The proposed decision is subject to comment by the parties and change by
the full CPUC before a final decision is issued. The CPUC is expected to
issue a final decision in the near future.
Electric Base Revenue Increase Proceeding:
Section 368(e) of the California Public Utilities Code, adopted as part of the
California electric industry restructuring legislation, provided for an
increase in the Utility's electric base revenues for 1997 and 1998, for
enhancement of transmission and distribution system safety and reliability.
In accordance with Section 368(e), the CPUC authorized a 1997 base revenue
increase of $164 million. For 1998, the CPUC authorized an additional base
revenue increase of $77 million, for a total authorized base revenue increase
for 1997 and 1998 of $406 million. Under Section 368(e), any underspending of
the 1997 revenue requirement would be carried over into 1998. Any
overspending during either 1997 and 1998 would not be recoverable from
ratepayers. Section 368(e) expenditures are subject to review by the CPUC.
In March 1999, the Utility filed its report on 1998 expenditures and
resubmitted its report on 1997 expenditures (originally submitted in May 1998)
as part of its application for consolidated review of its Section 368(e)
expenditures.
On July 16, 1999, the ORA filed its report on the Utility's 1998 Section
368(e) expenditures recommending a disallowance of $44.5 million. In its
report, the ORA recommended a disallowance for 1997 of $43.9 million
(increased from the previously reported $31 million recommended disallowance).
In total, the ORA recommends a disallowance related to 1997 and 1998 Section
368(e)expenditures of $88.4 million. In August 1999, The Utility Reform
Network (TURN) recommended a $14 million disallowance for both 1997 and 1998
Section 368(e) expenditures in addition to the ORA's $88.4 million
recommendation for a total recommended disallowance for 1997 and 1998
expenditures of $102.4 million. Of this amount, approximately $18 million
may be recoverable in other CPUC proceedings.
The Utility's response to the recommended disallowances was filed on
October 4, 1999 and hearings are scheduled to begin October 18, 1999. A
proposed decision is not expected before the first quarter of 2000. Any
proposed decision would be subject to comment by the parties and change by
the full CPUC before a final decision is issued.
Results of Operations
In this section, we present the components of our results of operations for
the three- and nine-month periods ended September 30, 1999 and 1998. Except
for the impacts of the cost of capital decisions, discussed above, the
Utility's 1999 earnings are based on the authorized amount of revenues in
effect during 1998 and do not include any portion of the requested revenue
increase. When a final decision in the GRC is issued by the CPUC, the
Utility's regulatory assets and net income will be adjusted to reflect the
revenue approved in the final decision. Any such adjustment could have a
material impact on the Utility's and PG&E Corporation's results of
operations.
<PAGE>
The table below shows for the three- and nine-month periods ended
September 30, 1999 and 1998, respectively, certain items from our Statement
of Consolidated Income detailed by Utility and National Energy Group
operations of PG&E Corporation. (In the "Total" column, the table shows the
combined results of operations for these groups.) The information for PG&E
Corporation (the "Total" column) excludes transactions between its
subsidiaries (such as the purchase of natural gas by the Utility from the
unregulated business operations). Following this table we discuss earnings
and explain why the components of our results of operations varied for the
three- and nine-month periods ended September 30, 1999, as compared to the
same periods in 1998.
<TABLE>
<CAPTION>
National Energy Group
----------------------------------------------------
PG&E GT Elimi-
---------------- nations &
Utility PG&EGen NW Texas PG&E ET PG&E ES Other (1) Total
------- ------- ------- ------- ------- ------- ------- -------
(in millions)
For the three-month period ended:
- ---------------------------------
September 30, 1999
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $ 2,587 $ 275 $ 56 $ 177 $3,490 $ 166 $ (371) $ 6,380
Operating expenses 2,101 259 26 174 3,521 186 (379) 5,888
Operating income 492
Other income, net 20
Interest expense, net 191
Income taxes 138
Net income 183
EBITDA (2) 1,097 38 47 17 (29) (18) 10 1,162
September 30, 1998
Operating revenues $ 2,563 $ 155 $ 58 $ 453 $2,156 $ 108 $ (186) $ 5,307
Operating expenses 2,051 118 25 478 2,159 135 (186) 4,780
Operating income 527
Other income, net 18
Interest expense, net 193
Income taxes 142
Net income 210
EBITDA (2) 1,199 49 45 (11) (3) (26) 4 1,257
For the nine-month period ended:
- --------------------------------
September 30, 1999
Operating revenues $ 6,905 $ 818 $ 166 $ 970 $8,145 $ 443 $ (990) $16,457
Operating expenses 5,545 753 76 1,001 8,181 501 (988) 15,069
Operating income 1,388
Other income, net 80
Interest expense, net 584
Income taxes 365
Net income 519
EBITDA (2) 2,845 146 128 22 (30) (51) (3) 3,057
September 30, 1998
Operating revenues $ 6,706 $ 354 $ 177 $1,490 $5,993 $ 243 $ (516) $14,447
Operating expenses 5,276 239 73 1,524 5,994 309 (516) 12,899
Operating income 1,548
Other income, net 25
Interest expense, net 586
<PAGE>
Income taxes 464
Net income 523
EBITDA (2) 2,704 137 138 15 2 (63) (22) 2,911
<FN>
(1) Net income on intercompany positions recognized by segments using mark to market accounting
is eliminated. Intercompany transactions are also eliminated.
(2) EBITDA measures earnings (after preferred dividends) before interest expense (net of
interest income), income taxes, depreciation and amortization.
</TABLE>
<PAGE>
Overall Results:
- ----------------
Net income decreased $27 million and $4 million for the three- and nine-month
periods ended September 30, 1999, as compared to the same periods in 1998.
The decreases are a result of declines in net income of $20 million and $35
million at the Utility; $11 million and $3 million at PG&EGen; and $17 million
and $19 million at PG&E ET, for the three- and nine-months ended September 30,
1999 and 1998, respectively. The Utility's decreases in net income are a
result of its disposition of a significant portion of its generating assets in
1998 and 1999, and the reduced authorized cost of capital from 11.2 percent in
1998 to 10.6 percent in 1999. The decreased net income at PG&EGen reflects
the negative impact of a fire at its 400 MW Salem Harbor Unit 4 power plant
which took the facility out of service for 32 days during a peak period of
summer demand; and mild weather in the Northeast United States for the
remainder of the quarter. PG&E ET experienced losses resulting from trading
positions in its United States and Canadian gas trading operations, and
increased infrastructure investment. These declines in net income were
partially offset by increased income at PG&E GT, whose financial performance
was positively impacted by the continued recovery in the natural gas liquids
markets, where the price spread between natural gas liquids and natural gas
increased from approximately five cents per gallon in the third quarter of
1998 to an average of 14 cents per gallon in the third quarter of 1999. PG&E
GT also benefited from decreased operating costs resulting from a
restructuring of operations in the first half of 1999.
In addition, during the second quarter of 1998, the Corporation recognized
a non-recurring charge of $.06 per share related to the disposition of its
Australian holdings. The charge resulted from the 22 percent currency
devaluation of the Australian dollar against the U.S. dollar.
Operating Revenues:
- -------------------
Utility:
Utility operating revenues increased by $24 million for the three-month period
ended September 30, 1999, as compared to the same period in 1998. The
majority of the increase is attributed to a $30 million increase in
residential and commercial gas revenues reflecting a higher average cost of
gas. In addition, commercial and agricultural electric sales were $9 million
higher reflecting the impact of abnormally high rainfall in 1998, which
reduced demand for irrigation water pumping in the third quarter of 1998.
Partially offsetting these increases was an $18 million decrease in
residential and small commercial electric customer sales due to the mild
weather experienced in California during the third quarter compared to the
prior year.
Utility operating revenues increased by $199 million for the nine-month
period ended September 30, 1999, as compared to the same period in 1998. This
increase is primarily due to: (1) a $135 million increase in gas residential
sales reflecting cooler temperatures, particularly during the first three
months of 1999, (2) a $61 million increase in revenues from residential and
small commercial electric customers reflecting customer growth, and (3) a $40
million increase in commercial and agricultural electric sales, as discussed
above. Partially offsetting these increases is $55 million of lower sales to
medium and large electric customers leaving for direct access.
<PAGE>
National Energy Group:
Operating revenues associated with the National Energy Group increased $1,234
million and $2,285 million for the three- and nine-month periods ended
September 30, 1999, as compared to the same periods in 1998. PG&EGen's
revenue increase for the three- and nine-month periods ended September 30,
1999, compared to the same period in 1998, include revenue increases of $128
million and $541 million, respectively, from its portfolio of electric
generating assets and power supply contracts acquired from New England
Electric System in September 1998.
PG&E ET's operating revenues increased $1,334 million and $2,152 million
for the three- and nine-month periods ended September 30, 1999, as compared to
the same periods in 1998. These increases were a result of increased trading
activity in each of PG&E ET's commodity markets. PG&E ET increased its
electric commodity revenues by $1,017 million and $2,049 million, and its gas
commodity revenues by $317 million and $103 million, for the three- and nine-
month periods ended September 30, 1999 and 1998, respectively.
PG&E ES' operating revenues increased $58 million and $200 million for the
three- and nine-month periods ended September 30, 1999, as compared to the
same periods in 1998, as a result of increases of $73 million and $194
million, respectively, in its electricity commodity sales portfolio in
California and New England. The increases in this quarter's electric
commodity sales were partially offset by a decrease in revenues from gas
sales.
The increases in operating revenues at PG&EGen, PG&E ET and PG&E ES were
partially offset by the decline in operating revenues at PG&E GT. PG&E GT's
operating revenues declined $278 million and $531 million for the three- and
nine-month periods ended September 30, 1999 compared to the same periods in
1998. The declines are a result of a decrease in the proportion of natural
gas volumes shipped for resale to transport-only volumes at PG&E GTT, and
lower interruptible transportation volumes at PG&E GT NW.
Operating Expenses:
- -------------------
Utility:
Operating expenses at the Utility increased $50 million and $269 million for
the three- and nine-month periods ended September 30, 1999, as compared to the
same periods in 1998. These increases resulted from increased ISO grid
management charges in the current year; increased recovery of stranded costs
(transition costs); and higher purchased gas volumes for the increase in
residential gas sales due to the cooler weather in the first quarter. These
increases were partially offset by decreased fuel, depreciation, and
environmental costs due to plant sales.
National Energy Group:
Operating expenses for the National Energy Group increased $1,251 million and
$2,373 million for the three- and nine-month periods ended September 30, 1999
as compared to the same periods in 1998. PG&EGen's operating expenses
increased as a result of its September 1998 acquisition of the electric
generating assets and power supply contracts discussed above. PG&E ET's
operating expenses increased as a result of its increased electric and gas
commodity purchasing activities in support of the trading activities described
<PAGE>
above and its increased investment in information technology systems and
personnel to manage the commodity pricing risk of the National Energy Group
businesses. PG&E ES's operating expenses increased as a result of increased
purchases of electricity to support the electric sales discussed above. These
increases were partially offset by decreases in PG&E GT's operating expenses
due to a decline in the volumes of gas purchased for resale. The year-to-date
operating expenses includes approximately $6 million of restructuring and
severance costs at the Gas Transmission business unit.
Income Taxes:
- -------------
Income taxes decreased $4 million and $99 million for the three- and nine-
month periods ended September 30, 1999 as compared to the same periods in
1998, due to a lower effective state income tax rate resulting from our
expanded business operations outside of California.
EBITDA:
- -------
Utility:
The Utility's EBITDA declined $102 million for the three-month period ended
September 30, 1999, compared to the same period in 1998. The Utility's
disposition of its fossil-fueled power plants reduced its sales to the PX for
the third quarter of 1999 by $254 million over the third quarter of 1998.
This reduction was partially offset by a $153 million decrease in the cost of
electric generation resulting from those same power plant sales.
The Utility's EBITDA for the nine-month period ended September 30, 1999,
increased by $141 million over the same period in 1998 as a result of
increased revenues from residential and small commercial electric customers
reflecting customer growth and increased residential gas sales reflecting
cooler temperatures, particularly during the first three months of 1999. In
addition, the Utility's sale of its fossil-fueled power plants resulted in a
decrease in the cost of electric generation. These changes were partially
offset by increased costs of gas to meet the increased sales demand, increases
in the cost of ancillary services and electricity purchased from the PX and a
reduction in the sales of electricity to the PX.
National Energy Group:
EBITDA for the National Energy Group increased $7 million and $5 million for
the three- and nine-month periods ended September 30, 1999, compared to
similar periods in 1998. PG&E GTT's EBITDA increased $28 million and $7
million, respectively, for the three- and nine-month periods, as a result of
the increased price spread between the price of natural gas liquids and
natural gas, and a decline in operating expenses resulting from a
restructuring of operations in the first half of 1999. In addition, PG& ES'
EBITDA increased by $8 and $12 million for the three- and nine-month periods
ended September 30, 1999 over 1998. These increases are a result of increased
sales volume and operating margin on its electric commodity and value-added
services sales. These increases were partially offset by declines at PG&E ET,
whose EBIDTA decreased $26 million and $32 million, respectively, for the
three- and nine-month periods ended September 30, 1999, compared to 1998.
These declines are a result of the losses on its trading positions in its
United States and Canadian gas operations and increased infrastructure
investment.
<PAGE>
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. We continually review the level of our
common stock dividend taking into consideration the impact of the changing
regulatory environment throughout the nation, the resolution of asset
dispositions, the operating performance of our business units, and our
capital and financial resources in general.
The CPUC requires the Utility to maintain its CPUC-authorized capital
structure, potentially limiting the amount of dividends the Utility may pay
PG&E Corporation. During 1999, the Utility has been in compliance with its
CPUC-authorized capital structure. PG&E Corporation and the Utility believe
that this requirement will not affect PG&E Corporation's ability to pay
common stock dividends. However, depending on the timing and outcome of the
valuation of the Utility's hydroelectric facilities discussed in "Generation
Divestiture" above, certain valuation methods could necessitate a waiver of
the CPUC's authorized capital structure in order to permit PG&E Corporation
or the Utility to continue paying common stock dividends at the current
level.
Liquidity and Financial Resources
Cash Flows from Operating Activities:
Net cash provided by PG&E Corporation's operating activities totaled $2,005
million and $2,515 million during the nine-month period ended September 30,
1999 and 1998, respectively. Net cash provided by the Utility's operating
activities totaled $1,926 million and $2,755 million during the nine-month
period ended September 30, 1999 and 1998, respectively.
Cash Flows from Financing Activities:
PG&E Corporation:
We fund investing activities from cash provided by operations after capital
requirements and, to the extent necessary, external financing. Our policy is
to finance our investments 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 our investing and disposition activities, we may repurchase equity and
long-term debt in order to manage the overall size and balance of our capital
structure.
During the nine-month period ended September 30, 1999 and 1998, we issued
$44 million and $48 million of common stock, respectively, primarily through
the Dividend Reinvestment Plan and the stock option plan component of the
Long-Term Incentive Program. During the nine-month period ended September
30, 1999 and 1998, we declared dividends on our common stock of $325 million
and $343 million, respectively.
During the nine-month period ended September 30, 1999 and 1998, we
repurchased $534 million and $1,159 million of our common stock,
respectively. These repurchases were executed through accelerated share
<PAGE>
repurchase programs. Under the most recent agreement, PG&E Corporation
repurchased in a specific transaction 16.6 million shares of its common
stock. In connection with this transaction, PG&E Corporation entered into a
forward contract with an investment institution. PG&E Corporation settled
the forward contract and its additional obligation of $29 million in
September 1999. There are no more outstanding shares to be repurchased.
We maintain a number of credit facilities throughout our organization to
support commercial paper programs, letters of credit, and other short term
liquidity requirements. At PG&E Corporation, we maintain two $500 million
revolving credit facilities, one of which expires in November 1999 and the
other in 2002. The PG&E Corporation credit facilities are used to support
the commercial paper program and other liquidity needs. The facility
expiring in 1999 may be extended annually for additional one-year periods
upon agreement between the lending institutions and us. There was $261
million of commercial paper outstanding at September 30, 1999. PG&E
Corporation introduced a $200 million Extendible Commercial Note (ECN)
program during the third quarter of 1999. The ECN program supplements PG&E
Corporation's short-term borrowing capability. There was $89 million of
extendible commercial notes outstanding at September 30, 1999, which are not
supported by the credit facilities.
PG&EGen maintains two credit facilities of $550 million each. One
agreement expired in August 1999 and was immediately renewed for a 364 day
period which expires in August 2000. The other facility will expire in
2003. The total amount outstanding at September 30, 1999, backed by the
facilities, was $910 million in commercial paper. Of these loans, $550
million is classified as noncurrent in the consolidated balance sheet.
At September 30, 1999, PG&E GTT had $177 million of outstanding short-term
bank borrowings related to four separate credit facilities. These lines may
be cancelled upon demand and bear interest at each respective bank's quoted
money market rate. The borrowings are unsecured and unrestricted as to use.
On June 30, 1999, PG&E GTT redeemed the outstanding balance of $69 million of
its senior notes, resulting in a gain on redemption of approximately $1.7
million.
PG&E GT NW maintains a $100 million revolving credit facility which
expires in the year 2002, but has an annual renewal option allowing the
facility to maintain a three year duration. PG&E GT NW also maintains a $50
million 364-day credit facility which expires in the year 2000, but can be
extended for successive 364-day periods. No amounts were outstanding under
either of these credit facilities at September 30, 1999. At September 30,
1999, PG&E GT NW had an outstanding commercial paper balance of $87 million,
which is classified as noncurrent.
Utility:
During the nine-month period ended September 30, 1999, the Utility
repurchased 20 million shares of its common stock from PG&E Corporation for
an aggregate purchase price of $725 million to maintain its authorized
capital structure. During the nine-month period ended September 30, 1999 and
1998, the Utility declared dividends on its common stock of $290 million and
$200 million. In October 1999, the Utility declared a dividend of $125
million payable to PG&E Corporation in October 1999.
<PAGE>
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during the nine-month period ended September 30, 1999 totaled
$454 million. Of this amount, (1) $217 million related to the Utility's rate
reduction bonds maturing; (2) $134 million related to the Utility's
repurchase of various mortgage bonds; (3) $67 million related to the
Utility's maturity of the Utility's 5.5 percent mortgage bonds; and (4) $36
million related to the maturities and redemption of various of the Utility's
medium term notes and other debt.
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. This facility is used to
support the Utility's commercial paper program and other liquidity
requirements. The total amount outstanding at September 30, 1999, backed by
this facility, was $77 million in commercial paper. There were no bank notes
outstanding at September 30, 1999.
Cash Flows from Investing Activities:
The primary uses of cash for investing activities are additions to property,
plant, and equipment; unregulated investments in partnerships; and
acquisitions.
The Utility's GRC application contained estimates of capital spending for
1999 in the amount of $1.6 billion, excluding capital expenditures for
divested fossil and geothermal power plants. These estimates were reflected
in the amount of base revenues requested by the Utility in its GRC filing.
The Utility has sold its remaining fossil generation facilities and its
geothermal generation facilities. These sales closed in April and May 1999.
The sales generated proceeds of $1,014 million.
Capital Investments:
PG&EGen is currently constructing two natural gas-fueled combined-cycle power
plants. These power plants, referred to as "merchant power plants", are being
built in New England and throughout the country for the purpose of selling
power as a commodity in the competitive marketplace without relying on long-
term contracts. The electricity generated by these plants will be sold on a
wholesale basis to local utilities and power marketers, including PG&E ET,
who, in turn, sell it to industrial, commercial, and residential electricity
customers.
Millenium Power, a 360 MW power plant, is located in Massachusetts, and is
scheduled to be placed in service in August 2000. The estimated cost to
construct Millenium Power is approximately $200 million. Lake Road
Generating Plant, a 792 MW power plant, is located in Connecticut, and is
scheduled to be placed in service in the year 2001. The estimated cost to
construct Lake Road Generating Plant is approximately $490 million.
Environmental Matters:
We are subject to laws and regulations established to both maintain and
improve the quality of the environment. Where our properties contain
hazardous substances, these laws and regulations require us to remove those
substances or remedy effects on the environment.
<PAGE>
At September 30, 1999, the Utility expects to spend $296 million over the
next 30 years for cleanup costs at identified sites. If other responsible
parties fail to pay or expected outcomes change, then these costs may be as
much as $481 million. Of the $296 million, the Utility has recovered $137
million (including remediation of generation plants divested, discussed
above) and expects to recover another $127 million in future rates. The
Utility mitigates its cost by seeking recovery from insurance carriers and
other third parties.
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 estimated 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.
Year 2000:
The Year 2000 (Y2K) issue exists because many computer programs use only two
digits to refer to a year, and were developed without considering the impact
of the upcoming change in the century. If PG&E Corporation's mission-
critical computer systems fail or function incorrectly due to not being made
Y2K ready, they could directly and adversely affect our ability to generate
or deliver our products and services or could otherwise affect revenues,
safety, or reliability for such a period of time as to lead to unrecoverable
consequences.
Our plan to address the Y2K issues focused primarily on mission-critical
systems whose components are categorized as in-house software, vendor
software, embedded systems, and computer hardware.
The four primary phases of our plan to address these systems were
inventory and assessment, remediation, testing, and certification.
Certification occurs when mission-critical systems are formally determined to
be Y2K ready. "Y2K ready" means that a system is suitable for continued use
into the year 2000.
PG&E Corporation's mission-critical items have been certified as Y2K ready
with a few exceptions at PG&E Gas Transmission-Northwest. These exceptions
are scheduled to be resolved by replacement or retirement of non-Y2K ready
systems in November 1999. Contingency plans are in place to address any
unlikely delays or problems.
The Utility is certifying its readiness to the CPUC prior to the November
1 deadline, and has previously notified the North American Electric
Reliability Council (NERC), and Nuclear Regulatory Commission (NRC) that it
is Y2K ready.
"Clean management" practices have been implemented to prevent systems from
becoming compromised. Even after systems are certified as Y2K ready, we are
continuing various kinds of validation and quality assurance efforts and may
do so into the year 2000 to minimize the risk of any significant disruption.
<PAGE>
In addition to internal systems, we also depend upon external parties,
including customers, suppliers, business partners, gas and electric system
operators, government agencies, and financial institutions to support the
functioning of our business. To the extent that any of these parties are
considered mission-critical to our business and experience Y2K problems in
their systems, our mission-critical business functions may be adversely
affected. To deal with this vulnerability, our program used a four phased
approach to address external parties: inventory, action planning, risk
assessment, and contingency planning. The contingency planning process also
addresses exposures that could result from failures in our own essential
business systems. Contingency plans are continually revised as necessary.
The Utility's contingency plans have been incorporated into its emergency
plans and include measures such as emergency back-up and recovery procedures,
augmenting automated applications with manual processes, and identification
of alternate suppliers. Electric transmission and generation plans are
coordinated with those of the California ISO and PX, and are consistent with
Western Systems Coordinating Council and NERC recommendations and NRC
guidelines. The plans were tested in Utility and gas-and-electric industry
drills in which the Utility participated throughout 1999, and will be updated
as necessary.
As of September 30, 1999, we estimate total costs to address Y2K problems
to be $212 million, of which $97 million is attributed to the Utility.
Included are systems replaced or enhanced for general business purposes and
whose implementation schedules is critical to our Y2K readiness.
Through September 1999, we spent approximately $179 million, of which $94
million was capitalized. The remaining $85 million was expensed. Future
costs, including contingency funds, to address Y2K issues are expected to be
$33 million, of which $13 million will be capitalized. The remaining $20
million will be expensed.
Although we expect our efforts and those of our external parties to be
successful, given the complex interaction of today's computing and
communications systems, we cannot be certain we will be completely
successful. Accordingly, we have considered the most reasonably likely worst
case Y2K scenarios that could affect us or the Utility, and we believe that
they mainly involve public overreaction before and during the New Year period
that could create localized telephone problems due to congestion, temporary
gasoline shortages, and curtailment of natural gas usage by customers. In
addition, it is reasonably likely that there will be minor technical failures
such as localized telephone outages and small isolated malfunctions in our
computer systems that will be immediately repaired. None of these reasonably
likely scenarios are expected to have a material adverse impact on the
Utility's or our financial position, results of operations, or cash flows.
Nevertheless, if we, or third parties with which we have significant business
relationships, fail to achieve and sustain Y2K readiness of mission-critical
systems, there could be a material adverse impact on the Utility and our
financial position, results of operations, and cash flows.
Price Risk Management Activities:
PG&E Corporation's daily value-at-risk for commodity price sensitive
derivative instruments as of September 30, 1999, is $1.3 million for trading
activities and $1.7 million for non-trading activities.
<PAGE>
In November 1998, the Emerging Issues Task Force of the Financial
Accounting Standards Board released Issue 98-10, Accounting for Energy
Trading and Risk Management Activities. This Issue states that all energy-
related contracts entered into with the objective of generating profits on or
from exposure to shifts or changes in market prices be marked to market with
the gains and losses reflected in the income statement. The Task Force
stipulates implementation for fiscal years beginning after December 15, 1998.
PG&E Corporation adopted this standard on January 1, 1999. The effect of
adoption on earnings and the financial position of PG&E Corporation was
immaterial.
On July 8, 1999, the CPUC authorized the Utility to recover the costs of
participating in the California Power Exchange block forward market.
Legal Matters:
In the normal course of business, both the Utility and PG&E Corporation are
named as parties in a number of claims and lawsuits. (See Note 6 of Notes to
Consolidated Financial Statements for further discussion of significant
pending legal matters.
<PAGE>
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 Price Risk Management
Activities, above.)
<PAGE>
PART II. OTHER INFORMATION
Item 4. Legal Proceedings
-----------------
As previously disclosed in PG&E Corporation and Pacific Gas
and Electric Company's Annual Report on Form 10-K for the
year ended December 31, 1998, Pacific Gas and Electric
Company is currently a defendant in three civil actions
pending in California courts. These cases are (1) Aguayo v.
Pacific Gas and Electric Company, filed March 15, 1995, in
Los Angeles County Superior Court, (2) Aguilar v. Pacific
Gas and Electric Company, filed October 4, 1996, in Los
Angeles County Superior Court, and (3) Acosta, et al. v.
Betz Laboratories, Inc., et al., filed November 27, 1996, in
Los Angeles Superior Court. These cases are collectively
referred to as the "Aguayo Litigation." In September 1999,
two cases which also had named PG&E Corporation as a
defendant (Little and Mustafa v. Pacific Gas and Electric
Company and PG&E Corporation and Whipple, et al. v. Pacific
Gas and Electric Company and PG&E Corporation, et al.) were
dismissed.
Each of the complaints in the Aguayo Litigation alleges
personal injuries and seeks compensatory and punitive
damages in an unspecified amount arising out of alleged
exposure to chromium contamination in the vicinity of
Pacific Gas and Electric Company's gas compressor stations
at Kettleman, Hinkley, and Topock, California. The
plaintiffs in the Aguayo Litigation include current and
former Pacific Gas and Electric Company employees, relatives
of current and former Company employees, residents in the
vicinity of the compressor stations, and persons who visited
the gas compressor stations. The plaintiffs also include
spouses or children of these plaintiffs who claim only loss
of consortium or injury through the alleged exposure of
their spouses or parents. In June 1998, the court found
that preconception claims are not recognizable under
California law and ordered the dismissal of such claims.
Pursuant to stipulation of the parties, the court has
entered the dismissals of 611 plaintiffs who either had
failed to respond to discovery or whose claims were based on
preconception injuries, from the Acosta, Aguilar, and Aguayo
cases. As a result of these dismissals, there are currently
approximately 1,650 plaintiffs in the Aguayo Litigation.
Although the trial date for the 20 trial test plaintiffs in
the Aguayo, Acosta and Aguilar cases had been set for
November 16, 1999, in Los Angeles Superior Court, the
parties have requested the court to extend the trial date in
these cases to May 1, 2000.
PG&E Corporation believes that the ultimate outcome of this
matter will not have a material adverse impact on its or
Pacific Gas and Electric Company's financial position or
results of operations.
Item 5. Other Information
-----------------
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, 1999, was
2.94. Pacific Gas and Electric Company's earnings to
combined fixed charges and preferred stock dividends ratio
for the nine months ended September 30, 1999, was
<PAGE>
2.79. 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 Officer Severance Policy, amended as of
July 21, 1999
Exhibit 10.2 Description of Compensation Arrangement
between PG&E Corporation and Thomas G. Boren
Exhibit 10.3 Description of Compensation Arrangement
between PG&E Corporation and Peter Darbee
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, 1999, for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter
ended September 30, 1999, for Pacific Gas and
Electric Company
(b) The following Current Reports on Form 8-K were filed
during the third quarter of 1999 and through the date hereof (1):
1. August 18, 1999
Item 5. Other Events
Announcement relating to legislative proposal regarding
Pacific Gas and Electric Company's hydroelectric assets
2. September 13, 1999
Item 5. Other Events
A. Valuation and Disposition of Hydroelectric Generating
Assets
B. Post-Transition Period Ratemaking Proceeding
C. Electric Base Revenue Increase
3. September 17, 1999 (Filed by PG&E Corporation only)
Item 5. Other Events
Change in management
4. October 1, 1999
Item 5. Other Events
Proposed Auction of Hydroelectric Generating Assets
(1) Unless otherwise noted, all Current Reports on Form 8-K
were filed under both Commission File Number 1-12609 (PG&E
Corporation) and Commission File Number 1-2348 (Pacific Gas
and Electric Company)
<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act
of 1934, the registrants have duly caused this report to be
signed on their behalf by the undersigned thereunto duly
authorized.
PG&E CORPORATION
and
PACIFIC GAS AND ELECTRIC COMPANY
CHRISTOPHER P. JOHNS
October 15, 1999 By __________________________
CHRISTOPHER P. JOHNS
Vice President and Controller
(PG&E Corporation)
Vice President and Controller
(Pacific Gas and Electric Company)
<PAGE>
Exhibit Index
Exhibit No. Description of Exhibit
10.1 Officer Severance Policy, amended as of July 21, 1999
10.2 Description of Compensation Arrangement between PG&E
Corporation and Thomas G. Boren
10.3 Description of Compensation Arrangement between PG&E
Corporation and Peter Darbee
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, 1999 for PG&E Corporation
27.2 Financial Data Schedule for the quarter ended
September 30, 1999 for Pacific Gas and
Electric Company
<PAGE>
EXHIBIT 10.1
PG&E CORPORATION
OFFICER SEVERANCE POLICY
(As Amended Effective as of July 21, 1999)
1. Purpose
-------
This is the controlling and definitive statement of the
Officer Severance Policy of PG&E Corporation
("Policy"). Since Officers are employed at the will of
PG&E Corporation and its subsidiaries ("Corporation"),
their employment with the Corporation may be terminated
at any time, with or without cause. The Policy, which
was first adopted effective November 1, 1998, provides
Officers of the Corporation in Officer Compensation
Bands I through V with severance benefits if their
employment is terminated.1/ Severance benefits for
officers not covered by this Policy will be provided
under policies or programs developed by the appropriate
lines of business in consultation with and the approval
by the Senior Human Resources Officer of the
Corporation.
The purpose of the Policy is to attract and retain
senior management by defining terms and conditions for
severance benefits, to provide severance benefits that
are part of a competitive total compensation package,
to provide consistent treatment for all terminated
officers, and to minimize potential litigation costs
associated with Officer termination of employment.
2. Termination of Employment Not Following a Change in
---------------------------------------------------
Control or Potential Change in Control
--------------------------------------
(a) Corporation's Obligations. If the Corporation
exercises its right to terminate an Officer's employment
without cause and such termination does not entitle Officer
to payments under Section 3, the Corporation shall give the
Officer thirty (30) days' advance written notice or pay in
lieu thereof. Except as provided in
Section 2(b) below, in consideration of the Officer's
agreement to the obligations described in Section 2(c) below
and to the arbitration provisions described in
Section 12 below, Corporation shall also provide the
following payments and benefits to Officer:
(1) The Corporation shall pay Officer a severance payment,
equal to (x) two, for Officers in Officer Bands I, II or III
or (y) one and one-half, for Officers in Officer Bands IV or
V times (the "Severance Multiple") the sum of the Officer's
annual base compensation and the Officer's Short-Term
Incentive Plan target award at the time of his or her
termination, to be paid in a lump sum. Annual base
compensation shall mean the
_______________________________
1/ Severance benefits for Officers who are currently covered
by an employment agreement will continue to be provided
solely under such agreements until their expiration at
which time this Policy will become effective for such
Officers.
<PAGE>
Officer's monthly base pay for the month in which the
Officer is given notice of termination, multiplied by 12.
If Officer is a participant in the Corporation's Defined
Benefit Supplemental Executive Retirement Plan ("SERP"),
Officer may elect to convert any portion of the amount
described in the preceding sentence to provide for
additional years of service and/or additional
years to Officer's age for purposes of calculating a benefit
under the SERP. The value of any amount so converted shall
be calculated using the same actuarial factors used in
calculating benefits under the Retirement Plan for Employees
of Pacific Gas and Electric Company. Any payments made
hereunder shall be less applicable taxes;
(2) If Officer is a participant in the SERP and if the
additional age resulting from a conversion under Section
2(a)(1) does not result in an age of 55 or greater, Officer
may elect to begin receiving an immediately payable SERP
benefit. If Officer elects to receive an immediately
payable SERP benefit, the Administrator shall use an
interest rate and actuarial factors which the Administrator,
in its sole discretion, has determined are appropriate to
reflect the true economic value to the Corporation of
providing an immediately payable SERP benefit;
(3) The incentive awards granted to Officer under the
Corporation's Long-Term Incentive Program which have not yet
vested as of the date of termination will continue to vest
over a period of years or portion thereof equal to the
Severance Multiple after the date of termination as if the
Officer had remained employed for such period. For vested
stock options as of the date of termination, the Officer
shall have the right to exercise such stock options at any
time within their respective terms or within
five years after termination, whichever is shorter. For
stock options that vest during a period of years or portion
thereof equal to the Severance Multiple, the Officer shall
have the right to exercise such options at any time within
five years after termination. Awards under the Performance
Unit Plan shall continue to vest and be payable during a
period of years or portion thereof equal to the Severance
Multiple. Any unvested Performance Unit Plan awards
remaining at the end of such period shall be forfeited;
(4) For Officers in Officer Bands I, II or III, two thirds
of the unvested Company stock units in the Officer's account
in the Corporation's Deferred Compensation Plan for Officers
which were awarded in connection with the Executive Stock
Ownership Program requirements ("SISOPs") shall vest upon
the Officer's termination, and one third shall be forfeited.
For Officers in Officer Bands IV and V, one third of any
unvested SISOPs shall vest upon the Officer's termination,
and two thirds shall be forfeited. Unvested stock units
attributable to SISOPs which becomes vested under this
provision shall be distributed to Officer in accordance with
the Deferred Compensation Plan after such stock units vest;
<PAGE>
(5) For a period of years or portion thereof equal to the
Severance Multiple, the Corporation shall pay the Officer's
COBRA premiums;
(6) If Officer is terminated after serving consecutively
for six months in a fiscal year, Officer shall be entitled
to receive a prorated bonus under the Corporation's Short-
Term Incentive Plan, at the time such bonus would otherwise
be paid, if any;
(7) To the extent not theretofore paid or provided, the
Corporation shall timely pay or provide to the Officer any
other amounts or benefits required to be paid or provided or
which the Officer is eligible to receive under any plan,
contract or agreement of the Corporation and its affiliated
companies; and
(8) Such career transition services as the Corporation's
Senior Human Resources Officer shall determine is
appropriate.
(b) Remedies. The Executive Officer shall be entitled to
recover damages for late or nonpayment of amounts which the
Corporation is obligated to pay hereunder. The Executive
Officer shall also be entitled to seek specific performance
of the Corporation's obligations and any other applicable
equitable or injunctive relief.
(c) Section 2(a) shall not apply in the event that the
Corporation terminates an Officer's employment "for cause."
Except as used in Section 3 of this Policy, "for cause"
means that the Corporation, acting in good faith based upon
information then known to it, determines that the Officer
has engaged in, committed, or is responsible for (1) serious
misconduct, gross negligence, theft, or fraud against the
Corporation; (2) refusal or unwillingness to perform his
duties; (3) inappropriate conduct in violation of
Corporation's equal employment opportunity policy; (4)
conduct which reflects adversely upon, or making any remarks
disparaging of, the Corporation, its Board of Directors,
Officers, or employees, or its affiliates or subsidiaries;
(5) insubordination; (6) any willful act that is likely to
have the effect of injuring the reputation, business, or
business relationship of the Corporation or its subsidiaries
or affiliates; (7) violation of any fiduciary duty; or (8)
breach of any duty of loyalty; or (9) any breach of the
restrictive covenants contained in Subsection 2(c) below.
Upon termination "for cause," the Corporation shall have no
liability to the Officer other than for accrued salary,
vacation benefits, and any vested rights the Officer may
have under the Corporation's benefit and compensation plans
under the general terms and conditions of the applicable
plan.
(d) Obligations of Officer
(1) Release of Claims. The Corporation shall
have no obligation to commence the payment of
the amounts and benefits described in
Section 2(a) until the latter of (1) the
delivery by Officer to the
<PAGE>
Corporation a fully executed comprehensive general
release of any and all known or unknown claims that
he or she may have against the Corporation
and a covenant not to sue in the form
prescribed by the Administrator, and (2) the
expiration of any revocation period
associated with the release to which the
Officer may be entitled under law.
(2) Covenant Not to Compete. (i) During the
period of Officer's employment with the
Corporation or its subsidiaries and for a
period of years or portion thereof equal to
the Severance Multiple thereafter (the
"Restricted Period"), Officer shall not, in
any county within the State of California or
in any city, county or area outside the State
of California within the United States or in
the countries of Canada or Mexico, directly
or indirectly, whether as partner, employee,
consultant, creditor, shareholder, or other
similar capacity, promote, participate, or
engage in any activity or other business
competitive with the Corporation's business
or that of any of its subsidiaries or
affiliates, without the prior written consent
of the Corporation's Chief Executive Officer.
Notwithstanding the foregoing, Officer may
have an interest in any public company
engaged in a competitive business so long as
Officer does not own more than 2 percent of
any class of securities of such company,
Officer is not employed by and does not
consult with, or becomes a director of, or
otherwise engage in any activities for, such
competing company.
(ii) The Corporation and its subsidiaries
presently conduct their businesses within
each county in the State of California and in
areas outside California that are located
within the United States, and it is
anticipated that the Corporation and its
subsidiaries will also be conducting business
within the countries of Canada and Mexico.
Such covenants are necessary and reasonable
in order to protect the Corporation and its
subsidiaries in the conduct of their
businesses. To the extent that the foregoing
covenant or any provision of this Section
2(c)(2)(ii) shall be deemed illegal or
unenforceable by a court or other tribunal of
competent jurisdiction with respect to (i)
any geographic area, (ii) any part of the
time period covered by such covenant, (iii)
any activity or capacity covered by such
covenant, or (iv) any other term or provision
of such covenant, such determination shall
not affect such covenant with respect to any
other geographic area, time period, activity
or other term or provision covered by or
included in such covenant.
(3) Soliciting Corporation Customers and
Employees. During the Restricted Period,
Officer shall not, directly or indirectly,
solicit or contact any customer or any
prospective customer of the Corporation for
any commercial pursuit that could be
reasonably construed to be in competition
with the Corporation, or induce, or attempt
to induce, any employees, agents or
consultants of or to the Corporation or any
of its
<PAGE>
subsidiaries or affiliates to do
anything from which Officer is restricted by
reason of this covenant nor shall Officer,
directly or indirectly, offer or aid to
others to offer employment to, or interfere
or attempt to interfere with any employment,
consulting or agency relationship with, any
employees, agents or consultants of the
Corporation, its subsidiaries and affiliates,
who received compensation of $75,000 or more
during the preceding
six (6) months, to work for any business
competitive with any business of the
Corporation, its subsidiaries or affiliates.
(4) Confidentiality. Officer shall not at any
time (including after termination of
employment) divulge to others, use to the
detriment of the Corporation, or use in any
business competitive with any business of the
Corporation, any trade secret, confidential
or privileged information obtained during his
employment with the Corporation, without
first obtaining the written consent of the
Corporation's Chief Executive Officer. This
paragraph covers but is not limited to
discoveries, inventions (except as otherwise
provided by California law), improvements,
and writings, belonging to or relating to the
affairs of the Corporation or of any of its
subsidiaries or affiliates, or any marketing
systems, customer lists or other marketing
data. Officer shall, upon termination of
employment for any reason, deliver to the
Corporation all data, records and
communications, and all drawings, models,
prototypes or similar visual or conceptual
presentations of any type, and all copies or
duplicates thereof, relating to all matters
contemplated by this paragraph.
(5) Assistance in Legal Proceedings. During the
Restricted Period, Officer shall, upon
reasonable notice from the Corporation,
furnish information and proper assistance
(including testimony and document production)
to the Corporation as may be reasonably
required by the Corporation in connection
with any legal, administrative or regulatory
proceeding in which it or any of its
subsidiaries or affiliates is, or may become,
a party, or in connection with any filing or
similar obligation of the Corporation imposed
by any taxing, administrative or regulatory
authority having jurisdiction, provided,
however, that the Corporation shall pay all
reasonable expenses incurred by Officer in
complying with this paragraph.
(6) Remedies. Upon Officer's failure to comply
with the provisions of this Section 2(c), the
Corporation shall have the right to
immediately terminate any unpaid amounts or
benefits described in Section 2(a) to
Officer. In the event of such termination, the
Corporation shall have no further obligations
under this Policy and shall be entitled to
recover damages. In the event of an
Officer's breach or threatened breach of any
of the covenants set forth in this Section
2(c), the Corporation shall also be entitled
to specific performance by Officer of any
such covenant and any other applicable
equitable or injunctive relief.
<PAGE>
3. Termination of Employment Following a Change in Control
-------------------------------------------------------
or Potential Change in Control
------------------------------
(a) If an Executive Officer's employment by the Corporation
or any subsidiary or successor of the Corporation shall be
subject to an Involuntary Termination within the Covered
Period, then the provisions of this Section 3 instead of
Section 2 shall govern the obligations of the Corporation as
to the payments and benefits it shall provide to the
Executive Officer. In the event that Executive Officer's
employment with the Corporation or an employing subsidiary
is terminated under circumstances which would not entitle
Executive Officer to payments under this Section 3,
Executive Officer shall only receive such benefits to which
he is entitled under Section 2, if any. In no event shall
Executive Officer be entitled to receive termination
benefits under both this Section 3 and Section 2.
All the terms used in this Section 3 shall have the
following meanings:
(1) "Affiliate" shall mean any entity which owns or
controls, is owned or is under common ownership or control
with, the Corporation.
(2) "Cause" shall mean (i) the willful and continued
failure of the Executive Officer to perform substantially
the Executive Officer's duties with the Corporation or one
of its affiliates (other than any such failure resulting
from incapacity due to physical or mental illness), after a
written demand for substantial performance is delivered to
the Executive Officer by the Board of Directors or the Chief
Executive Officer of the Corporation which specifically
identifies the manner in which the Board of Directors or
Chief Executive Officer believes that the Executive Officer
has not substantially performed the Executive Officer's
duties; or (ii) the willful engaging by the Executive
Officer in illegal conduct or gross misconduct which is
materially demonstrably injurious to the Corporation.
For purposes of the provision, no act or
failure to act, on the part of the Executive
Officer, shall be considered "willful" unless
it is done, or omitted to be done, by the
Executive Officer in bad faith or without
reasonable belief that the Executive
Officer's action or omission was in the best
interests of the Corporation. Any act, or
failure to act, based upon authority given
pursuant to a resolution duly adopted by the
Board of Directors or upon the instructions
of the Chief Executive Officer or a senior
officer of the Corporation or based upon the
advice of counsel for the Corporation shall
be conclusively presumed to be done, or
omitted to be done, by the Executive Officer
in good faith and in the best interests of
the Corporation. The cessation of employment
of the Executive Officer shall not be deemed
to be for Cause unless and until there shall
have been delivered to the Executive Officer
a copy of a resolution duly adopted by the
affirmative vote of not less than three-
quarters of the entire
<PAGE>
membership of the Board of Directors at a meeting
of the Board of Directors called and held for such
purpose (after reasonable notice is provided to the
Executive Officer and the Executive Officer
is given an opportunity, together with
counsel, to be heard before the Board of
Directors), finding that, in the good faith
opinion of the Board of Directors, the
Executive Officer is guilty of the conduct
described in subparagraph (i) or (ii) above,
and specifying the particulars thereof in
detail.
(3) "Change in Control" shall be deemed to have occurred
if:
(a) any "person" (as such term is used in
Sections 13(d) and 14(d)(2) of the Securities
Exchange Act of 1934, but excluding any benefit
plan for employees or any trustee, agent or other
fiduciary for any such plan acting in such
person's capacity as such fiduciary), directly or
indirectly, becomes the beneficial owner of
securities of the Corporation representing 20
percent or more of the combined voting power of
the Corporation's then outstanding securities;
(b) during any two consecutive years,
individuals who at the beginning of such a period
constitute the Board of Directors of the
Corporation cease for any reason to constitute at
least a majority of the Board of Directors of the
Corporation, unless the election or the nomination
for election by the shareholders of the
Corporation, of each new Director was approved by
a vote of at least two-thirds (2/3) of the
Directors then still in office who were Directors
at the beginning of the period; or
(c) the shareholders of the Corporation
shall have approved (i) any consolidation or
merger of the Corporation other than a merger or
consolidation which would result in the voting
securities of the Corporation outstanding
immediately prior thereto continuing to represent
(either by remaining outstanding or by being
converted into voting securities of the surviving
entity or any parent of such surviving entity) at
least 70 percent of the Combined Voting Power of
the Corporation, such surviving entity or the
parent of such surviving entity outstanding
immediately after such merger or consolidation;
(ii) any sale, lease, exchange or other transfer
(in one transaction or a series of related
transactions) of all or substantially all of the
assets of the Corporation; or (iii) any plan or
proposal for the liquidation or dissolution of the
Corporation.
(4) "Change in Control Date" shall mean the date on which a
Change in Control occurs.
<PAGE>
(5) "Combined Voting Power" shall mean the combined voting
power of the Corporation's or other relevant entity's then
outstanding voting securities.
(6) "Covered Period" shall mean the period commencing with
the Change in Control Date and terminating two (2) years
following said commencement; provided, however, that if a
Change in Control occurs and Executive Officer's employment
with the Corporation or the employing subsidiary is subject
to an Involuntary Termination before the Change in Control
Date but on or after a Potential Change in Control Date, and
if it is reasonably demonstrated by the Executive Officer
that such termination (i) was at the request of a third
party who has taken steps reasonably calculated to effect a
Change in Control, or (ii) otherwise arose in connection
with or in anticipation of a Change in Control, then the
Covered Period shall mean, as applied to Executive Officer,
the two-year period beginning on the date immediately before
the Potential Change in Control Date. In the case of
termination of employment following a Potential Change in
Control Date, references in the definition of "Good Reason"
to conditions in effect immediately prior to a Change in
Control shall be deemed to mean conditions in effect
immediately prior to Executive Officer's termination.
(7) "Disability" shall mean the absence of the Executive
Officer from the Executive Officer's duties with the
Corporation or the employing subsidiary on a full-time basis
for 180 consecutive business days as a result of incapacity
due to physical or mental illness which is determined to be
total and permanent by a physician selected by the
Corporation or its insurers and acceptable to the Executive
Officer or the Executive Officer's legal representative.
(8) "Executive Officer" shall mean officers of the
Corporation at the level of Senior Vice President and above.
(9) "Good Reason" shall mean any one or more of the
following which takes place within the Covered Period:
a) An adverse change in Executive Officer's
status or position(s) as in effect immediately
before a Change in Control or Potential Change in
Control, including, without limitation, the
assignment to the Executive Officer of any duties
inconsistent in any respect with the Executive
Officer's position (including status, offices,
titles and reporting requirements, including
reporting requirements under Section 16 of the
Securities Exchange Act of 1934), authority,
duties or responsibilities prior to a Change in
Control or Potential Change in Control, or any
other action by the Corporation which results in
the diminution in such position, authority, duties
or responsibilities prior to a Change in Control
or Potential Change in
<PAGE>
Control, excluding for this purpose an isolated,
insubstantial and inadvertent action not taken in
bad faith and which is remedied by the Corporation
promptly after receipt of notice thereof given by the
Executive Officer;
b) Executive Officer's base salary is
reduced from that provided to him immediately
before the Change in Control Date or as the same
may be increased from time to time thereafter,
unless such reduction is part of an
across-the-board reduction for all similarly
situated executives, including executives of the
other party to the transaction that results in the
Change in Control;
c) Executive Officer's eligibility to
participate in bonus, stock option, incentive
award and other compensation plans which provide
opportunities to receive compensation is
diminished from that provided to him immediately
before the Change in Control Date, unless
substantially equal benefits are provided to
Executive Officer under comparable compensation
plans, or unless such reduction is part of an
across-the-board reduction for all similarly
situated executives, including executives of the
other party to the transaction that results in the
Change in Control;
d) The aggregate projected value of
Executive Officer's employee benefits (including
but not limited to supplemental and excess
retirement programs, medical, dental, life
insurance and long-term disability plans) and
perquisites is diminished from that provided to
him immediately before the Change in Control Date,
unless such reduction is part of an
across-the-board reduction for all similarly
situated executives, including executives of the
other party to the transaction that results in the
Change in Control;
e) A change in Executive Officer's
principal place of employment by Corporation
(including its subsidiaries) to a location more
than thirty-five miles from Executive Officer's
principal place of employment immediately before
the Change in Control Date;
f) A reasonable determination by the Board
of Directors that, as a result of a Change in
Control and a change in circumstances thereafter
significantly affecting his position, he is unable
to exercise the authorities, powers, function or
duties attached to his position immediately before
the Change in Control Date;
g) The failure of the Corporation to obtain
the assumption of this Policy by any successor
contemplated in Section 7, hereof; or
<PAGE>
h) The material failure of the Corporation
to fulfill its obligations under this Policy, to
the extent not remedied in a reasonable period of
time after the Corporation's receipt of written
notice from Executive Officer specifying the
material failure by the Corporation.
(10) "Involuntary Termination" shall mean a termination (i)
by the Corporation without Cause, or (ii) by Executive
Officer following Good Reason; provided, however, the term
"Involuntary Termination" shall not include termination of
Executive Officer's employment due to Executive Officer's
death, Disability, or voluntary retirement.
(11) "Potential Change in Control" shall mean the earliest
to occur of (i) the date on which the Corporation executes
an agreement or letter of intent, where the consummation of
the transaction described therein would result in the
occurrence of a Change in Control, (ii) the date on which
the Board of Directors approves a transaction or series of
transactions, the consummation of which would result in a
Change in Control, or (iii) the date on which a tender offer
for the Corporation's voting stock is publicly announced,
the completion of which would result in a Change in Control;
provided, however, that if such Potential Change in Control
terminates by its terms, such transaction shall no longer
constitute a Potential Change in Control.
(12) "Potential Change in Control Date" shall mean the date
on which a Potential Change in Control occurs.
(13) "Reference Salary" shall mean the greater of (i) the
annual rate of Executive Officer's base salary from the
Corporation or the employing subsidiary in effect
immediately before the date of Executive Officer's
Involuntary Termination, or (ii) the annual rate of
Executive Officer's base salary from the Corporation or the
employing subsidiary in effect immediately before the Change
in Control Date.
(14) "Termination Date" shall be the date specified in the
written notice of termination of Executive Officer's
employment given by either party in accordance with Section
3(b) of this Policy.
(b) Notice of Termination. During the Covered Period, in
the event that the Corporation (including an employing
subsidiary) or Executive Officer terminates Executive
Officer's employment with the Corporation or employing
subsidiary, the party terminating employment shall give
written notice of termination to the other party, specifying
the Termination Date and the specific termination provision
in this Section 3 that is relied upon, if any, and setting
forth in reasonable detail the facts and circumstances
claimed to provide a basis for termination of Executive
Officer's employment under the provision so indicated.
<PAGE>
The Termination Date shall be determined as follows: (i) if
Executive Officer's employment is terminated for Disability,
thirty (30) days after a Notice of Termination is given
(provided that Executive Officer shall not have returned to
the full-time performance of Executive Officer's duties
during such 30-day period); (ii) if Executive Officer's
employment is terminated by the Corporation in an
Involuntary Termination, five days after the date the Notice
of Termination is received by Executive Officer; and (iii)
(as defined in this Section 3) if Executive Officer's
employment is terminated by the Corporation for Cause, the
date specified in the Notice of Termination, provided, that
the events or circumstances cited by the Board of Directors
as constituting Cause are not cured by Executive Officer
during any cure period that may be offered by the Board of
Directors. The Date of Termination for a resignation of
employment other than for Good Reason shall be the date set
forth in the applicable notice, which shall be no earlier
than ten (10) days after the date such notice is received by
the Corporation, unless waived by the Corporation.
During the Covered Period, a notice of termination given by
Executive Officer for Good Reason shall be given within
three (3) months after occurrence of the event on which
Executive Officer bases his notice of termination and shall
provide a Termination Date not more than sixty (60) days
after the notice of termination is given to the Corporation.
(c) Corporation's Obligations. If Executive Officer's
employment by the Corporation or any subsidiary or successor
of the Corporation shall be subject to an Involuntary
Termination within the Covered Period, then the Corporation
shall provide Executive Officer the following benefits:
(1) The Corporation shall pay to the Executive Officer a
lump sum in cash within thirty (30) days after the
Termination Date:
a) the sum of (1) any earned but unpaid
base salary through the Termination Date at the
rate in effect at the time of the notice of
termination to the extent not theretofore paid;
(2) the Executive Officer's target bonus under the
Short-Term Incentive Plan of the Corporation, an
Affiliate, or a predecessor, for the fiscal year
in which the Termination Date occurs (the "Target
Bonus"); and (3) any accrued but unpaid vacation
pay, in each case to the extent not theretofore
paid; and
b) the amount equal to the product of (1) three and
(2) the sum of (x) the Reference Salary and (y) the Target
Bonus.
(2) Remedies. The Executive Officer shall be entitled to
recover damages for late or nonpayment of amounts which the
Corporation is obligated to pay hereunder. The Executive
Officer shall also be entitled to seek specific
<PAGE>
performance of the Corporation's obligations and any
other applicable equitable or injunctive relief.
(d) Adjustment for Excise Taxes. If any portion of the
payments to the Executive Officer under this Section 3 or
under any other plan, program, or arrangement maintained by
the Corporation (a "Payment") would be subject to the excise
tax levied under Section 4999 of the Internal Revenue Code
("Code"), or any interest or penalties are incurred by
Executive Officer with respect to such excise tax (such
excise tax together with such interest and penalties are
referred to herein as the "Excise Tax"), then the
Corporation shall make an additional payment to Executive
Officer (a "Tax Restoration Payment") in an amount such that
after payment by the Executive Officer of all taxes
(including any interest or penalties imposed with respect to
such taxes), including, without limitation, any income taxes
(and any interest and penalties imposed with respect
thereto) and Excise Tax imposed upon the Tax Restoration
Payment, the Executive Officer retains an amount of the Tax
Restoration Payment equal to the Excise Tax imposed upon the
Payments. The payment of a Tax Restoration Payment under
this Section 3 shall not be conditioned upon the Executive
Officer's termination of employment.
All determinations and calculations required to be
made under this Section 3(d) shall be made by
Deloitte & Touche (the "Accounting Firm"), which
shall provide its determination (the
"Determination"), together with detailed
supporting calculations regarding the amount of
any Tax Restoration Payment and any other relevant
matter, both to the Corporation and the Executive
Officer within five (5) days of the termination of
the Executive Officer's employment, if applicable,
or such earlier time as is requested by the
Corporation or the Executive Officer (if the
Executive Officer reasonably believes that any of
the Payments may be subject to Excise Tax). If
the Accounting Firm determines that no Excise Tax
is payable by the Executive Officer, it shall
furnish the Executive Officer with a written
statement that such Accounting Firm has concluded
that no Excise Tax is payable (including the
reasons therefor) and that the Executive Officer
has substantial authority not to report any Excise
Tax on the Executive Officer's federal income tax
return. If a Tax Restoration Payment is
determined to be payable, it shall be paid to the
Executive Officer within five (5) days after the
Determination is delivered to the Corporation or
the Executive Officer. Any determination by the
Accounting Firm shall be binding upon the
Corporation and the Executive Officer, absent
manifest error.
As a result of uncertainty in the application of
Section 4999 of the Code at the time of the
initial determination by the Accounting Firm
hereunder, it is possible that Tax Restoration
Payments not made by the Corporation should have
been made ("Underpayment") or that Tax Restoration
Payments will have been made by the Corporation
which should not have been made ("Overpayment").
In either such event, the Accounting Firm shall
determine the amount of the Underpayment or
Overpayment that has occurred. In the case of an
Underpayment, the amount of
<PAGE>
such Underpayment shall be promptly paid by the Corporation
to or for the benefit of the Executive Officer. In the
case of an Overpayment, the Executive Officer
shall, at the direction and expense of the
Corporation, take such steps as are reasonably
necessary (including the filing of returns and
claims for refund), follow reasonable instructions
from, and procedures established by, the
Corporation, and otherwise reasonably cooperate
with the Corporation to correct such Overpayment,
provided, however, that (i) the Executive Officer
shall in no event be obligated to return to the
Corporation an amount greater than the net after-
tax portion of the Overpayment that the Executive
Officer has retained or has recovered as a refund
from the applicable taxing authorities, and (ii)
this provision shall be interpreted in a manner
consistent with the intent of the Tax Restoration
Payment paragraph above, which is to make the
Executive Officer whole, on an after-tax basis,
from the application of Excise Tax, it being
understood that the correction of an Overpayment
may result in the Executive Officer's repaying to
the Corporation an amount that is less than the
Overpayment.
4. Administration
--------------
The Policy shall be administered by the Senior Human
Resources Officer of the Corporation ("Administrator"),
who shall have the authority to interpret the Policy
and make and revise such rules as may be reasonably
necessary to administer the Policy. The Administrator
shall have the duty and responsibility of maintaining
records, making the requisite calculations, securing
Officer releases, and disbursing payments hereunder.
The Administrator's interpretations, determinations,
rules, and calculations shall be final and binding on
all persons and parties concerned.
5. No Mitigation
-------------
Payment of the amounts and benefits under Section 2(a)
and Section 3 (except as otherwise provided in Section
2(a)(4)) shall not be subject to offset, counterclaim,
recoupment, defense or other claim, right or action
which the Corporation may have and shall not be subject
to a requirement that Officer mitigate or attempt to
mitigate damages resulting from Officer's termination
of employment.
6. Amendment and Termination
-------------------------
The Corporation, acting through its Nominating and
Compensation Committee, reserves the right to amend or
terminate the Policy at any time; provided, however,
that any amendment which would reduce the aggregate
level of benefits, or terminate the Policy, shall not
become effective prior to the third anniversary of the
Corporation giving notice to Officers of such amendment
or termination.
<PAGE>
7. Successors
----------
The Corporation will require any successor (whether
direct or indirect, by purchase, merger, consolidation
or otherwise) to all or substantially all of the
business or assets of the Corporation expressly to
assume and to agree to perform its obligations under
this Policy in the same manner and to the same extent
that the Corporation would be required to perform such
obligations if no such succession had taken place;
provided, however, that no such assumption shall
relieve the Corporation of its obligations hereunder.
As used herein, the "Corporation" shall mean the
Corporation as hereinbefore defined and any successor
to its business and/or assets as aforesaid which
assumes and agrees to perform its obligations by
operation or law or otherwise.
This Policy shall inure to the benefit of and be
binding upon the Officer (and Officer's personal
representatives and heirs), Corporation and its
successors and assigns, and any such successor or
assignee shall be deemed substituted for the
Corporation under the terms of this Policy for all
purposes. As used herein, "successor" and "assignee"
shall include any person, firm, corporation or other
business entity which at any time, whether by purchase,
merger or otherwise, directly or indirectly acquires
the stock of the Corporation or to which the
Corporation assigns this Policy by operation of law or
otherwise. If Officer should die while any amount
would still be payable to Officer hereunder if Officer
had continued to live, all such amounts, unless
otherwise provided herein, shall be paid in accordance
with this Policy to Officer's devisee, legatee or other
designee, or if there is no such designee, to Officer's
estate.
8. Nonassignability of Benefits
----------------------------
The payments under this Policy or the right to receive
future payments under this Policy may not be
anticipated, alienated, pledged, encumbered, or subject
to any charge or legal process, and if any attempt is
made to do so, or a person eligible for payments
becomes bankrupt, the payments under the Policy of the
person affected may be terminated by the Administrator
who, in his or her sole discretion, may cause the same
to be held if applied for the benefit of one or more of
the dependents of such person or make any other
disposition of such benefits that he or she deems
appropriate.
9. Nonguarantee of Employment
--------------------------
Officers covered by the Policy are at-will employees,
and nothing contained in this Policy shall be construed
as a contract of employment between the Officer and the
Corporation (or, where applicable, a subsidiary or
affiliate of the Corporation), or as a right of the
Officer to continued employment, or to remain as an
Officer, or as a limitation on the right of the
Corporation (or a subsidiary or affiliate of the
Corporation) to discharge Officer at any time, with or
without cause.
<PAGE>
10. Benefits Unfunded and Unsecured
-------------------------------
The payments under this Policy are unfunded, and the
interest under this Policy of any Officer and such
Officer's right to receive payments under this Policy
shall be an unsecured claim against the general assets
of the Corporation.
11. Applicable Law
--------------
All questions pertaining to the construction, validity,
and effect of the Policy shall be determined in
accordance with the laws of the United States and, to
the extent not preempted by such laws, by the laws of
the state of California.
12. Arbitration
-----------
With the exception of any request for specific
performance, injunctive or other equitable relief, any
dispute or controversy of any kind arising out of or
related to this Policy, Officer's employment with the
Corporation (or with the employing subsidiary), the
termination thereof or any claims for benefits shall be
resolved exclusively by final and binding arbitration
in accordance with the Commercial Arbitration Rules of
the American Arbitration Association then in effect.
Provided, however, that in making their determination,
the arbitrators shall be limited to accepting the
position of the Officer or the position of the
Corporation, as the case may be. The only claims not
covered by this Section 12 are claims for benefits
under workers' compensation or unemployment insurance
laws; such claims will be resolved under those laws.
The place of arbitration shall be San Francisco,
California. Parties may be represented by legal
counsel at the arbitration but must bear their own fees
for such representation. The prevailing party in any
dispute or controversy covered by this Section 12, or
with respect to any request for specific performance,
injunctive or other equitable relief, shall be entitled
to recover, in addition to any other available remedies
specified in this Policy, all litigation expenses and
costs, including any arbitrator or administrative or
filing fees and reasonable attorneys' fees. Both the
Officer and the Corporation specifically waive any
right to a jury trial on any dispute or controversy
covered by this Section 12. Judgment may be entered on
the arbitrators' award in any court of competent
jurisdiction.
<PAGE>
Exhibit 10.2
Description of Compensation Arrangement
Between PG&E Corporation and Thomas G. Boren
Position: Executive Vice President, President and Chief
Executive Officer of PG&E Corporation National Energy Group, with
responsibility for all of PG&E Corporation's national businesses.
Compensation and Benefit Arrangement:
1. An annual base salary of $600,000 ($50,000 monthly) subject
to possible increases through annual salary review plan.
2. A target annual incentive of $450,000, which equals 75% of
base salary, in an annual incentive plan under which actual
incentive dollars can range from $0 to $900,000 based on
performance relative to established goals. This would be
prorated for 1999.
3. An annual perquisite allowance of $15,500.
4. An award of 12,000 performance units under the Performance
Unit Plan (PUP). The value of these units is tied to the price
of PG&E Corporation common stock. The estimated target value of
this award is $402,000 based on a value of $33.50 per share. A
stock option grant of 150,000 shares of PG&E Corporation common
stock. The 150,000 options will be granted and priced as of the
day of election by the Board of Directors. The estimated value
of this grant is $900,000, based on a Black-Scholes value of
$6.00 per option.
5. Participation in the PG&E Corporation Executive Stock
Ownership Program. The program provides an incentive for
achievement of certain stock ownership targets. Target ownership
level is two times base salary. If ownership target achieved
within one year, entitled to receive an incentive of $336,000, in
the form of Phantom Stock units, which vest after three years.
6. One-time bonus of $250,000 payable within 30 days of date of
hire, subject to normal payroll withholdings. At officer's
election, all or a portion of this amount may be deferred into
the PG&E Corporation Deferred Compensation Plan. If officer
decides to leave PG&E Corporation within one year of start date,
a prorated amount of this bonus must be refunded to the company.
7. Participation in and full recognition of officer's credited
years of service with Southern Company under the PG&E Corporation
supplemental defined benefit executive retirement plan. Benefit
payable from the plan shall be reduced by any benefit payable
from Southern Company's comparable plan, not including any
special enhancement payable as part of separation from Southern.
8. Providing officer meets general business goals for 1999,
2000, and 2001, the Corporation will credit to officer's deferred
compensation account an amount equal to $1,000,000 payable in
three equal annual installments on December 31, 1999, December
31, 2000, and December 31, 2001. Should officer decide to
terminate prior to the payment of an installment, that
installment, as well as any
<PAGE>
remaining installment, will be forfeited. The credited funds
will be allocated to the PG&E Corporation Phantom Stock Fund.
Payment of credited funds will occur in accordance with officer's
selected payout option under the terms of the PG&E Corporation
Deferred Compensation Plan.
9. Coverage under the PG&E Corporation Officer Severance Policy
(a copy of which is enclosed) which provides for a severance
benefit of two times pay plus annual target bonus in the event
that officer's employment is terminated by the Corporation
without cause. The Policy also provides for the continued
vesting of (i) stock options, (ii) Phantom Stock units awarded
under the Executive Stock Ownership Program, and (iii) other long-
term incentive awards.
10. Participation in PG&E Corporation's health and welfare
benefit plans.
11. Four weeks of paid vacation per year.
12. Executive relocation assistance. Benefit will include a
mortgage subsidy equal to $20,000 per $100,000 of loan value,
limited to a loan amount of $1,500,000. This subsidy is
applicable to principle and interest only. The duration of the
subsidy is five years, with a maximum subsidy of $300,000
($60,000 per year). The subsidy will be paid directly to a
company-designated lender, and the mortgage will be subject to
minimum down payment requirements.
A number of compensation elements, as well as election as an
officer of PG&E Corporation, are subject to Board of Directors'
approval.
Exhibit 10.3
Description of Compensation Arrangement
Between PG&E Corporation and Peter Darbee
Position: Senior Vice President and Chief Financial Officer
of PG&E Corporation effective October 1, 1999.
Compensation and Benefit Arrangement:
1. An annual base salary of $400,000 ($33,333 per month)
subject to possible increases through merit review plan.
2. A target annual bonus of $200,000, which equals 50% of
base salary, in an annual incentive plan under which actual
bonus dollars can reach from 0 to $400,000 based on
performance relative to established goals. This would be pro-
rated for 1999.
3. An annual perquisite allowance of $15,500.
4. An award of 7,000 performance units under PG&E
Corporation Performance Unit Plan (PUP). The value of these
units is tied to the relative total shareholder value of PG&E
Corporation common stock as compared with other energy
companies. The estimated value of this award is $227,500
based on an estimated value of $32.50 per share of PG&E
Corporation stock.
5. A stock option grant of 150,000 shares of PG&E
Corporation common stock. These options will be granted and
priced as of the day of election by the Board of Directors to
new position. The estimated value of this grant is $900,000
based on a Black-Scholes value of $6.00 per option.
6. Participation in the PG&E Corporation Executive Stock
Ownership Program. The program provides an incentive for
achievement of certain stock ownership targets. Officer's
target is two times base salary. If officer achieves
ownership target within one year, officer will receive an
incentive of $224,000 in the form of Phantom Stock units
which vest after three years.
7. Participation in the PG&E Corporation Deferred
Compensation Plan.
8. A credit to officer's Deferred Compensation Plan account
of a total amount equal to $1,200,000, to be credited to
officer's account - providing officer meets general business
goals for 1999, 2000, and 2001 - in three equal installments
on January 1, 2000, January 1, 2001, and January 1, 2002.
The credited funds will be allocated to the PG&E Corporation
Phantom Stock Fund. Payment of credited funds will occur in
accordance with selected payout options under the terms of
the PG&E Corporation Deferred Compensation Plan. Should
officer terminate
<PAGE>
employment prior to the crediting of an installment, that
installment, as well as any remaining installments, will be
forfeited. However, should officer's employment be terminated
such that officer is entitled to benefits under the PG&E
Corporation Officer Severance Policy, any uncredited amounts
will be immediately credited to officer's account.
9. Participation in the PG&E Corporation health and benefit
plans, including defined contribution retirement savings
plan.
10. Four weeks of paid vacation per year.
11. A one-time bonus of $50,000 payable within 30 days of
officer's hire, subject to normal payroll withholdings.
Officer may defer all or a portion of this amount into the
PG&E Corporation Deferred Compensation Plan. Should officer
decide to leave PG&E Corporation within one year of start
date, a prorated amount of this bonus must be refunded to the
company.
A number of these compensation elements, as well as election
as an officer of PG&E Corporation, are subject to Board of
Directors approval.
<TABLE>
EXHIBIT 11
PG&E CORPORATION
COMPUTATION OF EARNINGS PER COMMON SHARE
<CAPTION>
- ----------------------------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
-------------------- ------------------------
(in millions, except per share amounts) 1999 1998 1999 1998
- ----------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
BASIC EARNINGS PER SHARE (EPS)1
Earnings available for common stock $ 183 $ 210 $ 519 $ 523
========== ========== ========== ==========
Average common shares outstanding 367 382 369 382
========== ========== ========== ==========
Basic EPS $ 0.50 $ 0.55 $ 1.41 $ 1.37
========== ========== ========== ==========
DILUTED EARNINGS PER SHARE (EPS)1
Earnings available for common stock $ 183 $ 210 $ 519 $ 523
========== ========== ========== ==========
Average common shares outstanding 367 382 369 382
Add: outstanding options, reduced by the
number of shares that could be
repurchased with the proceeds from
such exercise (at average market price) 1 1 1 1
---------- ---------- ---------- ----------
Average common shares outstanding as
adjusted 368 383 370 383
========== ========== ========== ==========
Diluted EPS $ 0.50 $ 0.55 $ 1.40 $ 1.37
========== ========== ========== ==========
- ----------------------------------------------------------------------------------------------
<FN>
1 This presentation is submitted in accordance with Item 601(b)(11) of Regulation S-K and Statement
of Financial Accounting Standards No. 128.
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12.1
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
- ---------------------------------------------------------------------------------------------------
Nine Months Year ended December 31,
ended -------------------------------------------------------
(dollars in millions) September 30, 1999 1998 1997 1996 1995 1994
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 516 $ 729 $ 768 $ 755 $ 1,339 $1,007
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates - - - 3 4 (3)
Income tax expense 424 629 609 555 895 837
Net fixed charges 482 673 628 683 716 729
-------- -------- -------- -------- -------- --------
Total Earnings $ 1,422 $ 2,031 $ 2,005 $ 1,996 $ 2,954 $ 2,570
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 394 $ 585 $ 485 $ 574 $ 616 $ 639
Interest on short-
term borrowings 63 50 101 75 83 77
Interest on capital leases 1 2 2 3 3 2
Capitalized Interest 1 - 1 1 - 2
AFUDC Debt 6 12 16 7 11 11
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 18 24 24 24 3 -
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 483 $ 673 $ 629 $ 684 $ 716 $ 731
======== ======== ======== ======== ======== ========
Ratios of Earnings to
Fixed Charges 2.94 3.02 3.19 2.92 4.13 3.52
- ----------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to
fixed charges, "earnings" represent net income adjusted for the minority interest in
losses of less than 100% owned affiliates, cash distributions from and equity in
undistributed income or loss of Pacific Gas and Electric Company's less than 50% owned
affiliates, income taxes and fixed charges (excluding capitalized interest). "Fixed
charges" include interest on long-term debt and short-term borrowings (including a
representative portion of rental expense), amortization of bond premium, discount and
expense, interest of subordinated debentures held by trust, interest on capital leases, and
earnings required to cover the preferred stock dividend requirements.
</TABLE>
<PAGE>
<TABLE>
EXHIBIT 12.2
PACIFIC GAS AND ELECTRIC COMPANY
COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
<CAPTION>
- ----------------------------------------------------------------------------------------------------
Nine months Year ended December 31,
ended -------------------------------------------------------
(dollars in millions) September 30, 1999 1998 1997 1996 1995 1994
- ----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Earnings:
Net income $ 516 $ 729 $ 768 $ 755 $ 1,339 $ 1,007
Adjustments for minority
interests in losses of
less than 100% owned
affiliates and the
Company's equity in
undistributed losses
(income) of less than
50% owned affiliates - - - 3 4 (3)
Income tax expense 424 629 609 555 895 837
Net fixed charges 482 673 628 683 716 729
-------- -------- -------- -------- -------- --------
Total Earnings $ 1,422 $ 2,031 $ 2,005 $ 1,996 $ 2,954 $ 2,570
======== ======== ======== ======== ======== ========
Fixed Charges:
Interest on long-
term debt, net $ 394 $ 585 $ 485 $ 574 $ 616 $ 639
Interest on short-
term borrowings 63 50 101 75 83 77
Interest on capital leases 1 2 2 3 3 2
Capitalized Interest 1 - 1 1 - 2
AFUDC Debt 6 12 16 7 11 11
Earnings required to
cover the preferred stock
dividend and preferred
security distribution
requirements of majority
owned trust 18 24 24 24 3 -
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 483 $ 673 $ 629 $ 684 $ 716 $ 731
-------- -------- -------- -------- -------- --------
Preferred Stock Dividends:
Tax deductible dividends $ 7 $ 9 $ 10 $ 10 $ 11 $ 5
Pretax earnings required
to cover non-tax
deductible preferred
stock dividend
requirements 19 31 39 39 100 96
-------- -------- -------- -------- -------- --------
Total Preferred
Stock Dividends $ 26 $ 40 $ 49 $ 49 $ 111 $ 101
-------- -------- -------- -------- -------- --------
Total Combined Fixed
Charges and Preferred
Stock Dividends $ 509 $ 713 $ 678 $ 733 $ 827 $ 832
======== ======== ======== ======== ======== ========
Ratios of Earnings to
Combined Fixed Charges and
Preferred Stock Dividends 2.79 2.85 2.96 2.72 3.57 3.09
- ---------------------------------------------------------------------------------------------------
<FN>
Note: For the purpose of computing Pacific Gas and Electric Company's ratios of earnings to
combined fixed charges and preferred stock dividends, "earnings" represent net income
adjusted for the minority interest in losses of less than 100% owned affiliates, cash
distributions from and equity in undistributed income or loss of Pacific
Gas and Electric Company's less than 50% owned affiliates, income taxes and fixed charges
(excluding capitalized interest). "Fixed charges" include interest on long-term debt and
short-term borrowings (including a representative portion of rental expense), amortization
of bond premium, discount and expense, interest on capital leases, interest of subordinated
debentures held by trust, and earnings required to cover the preferred stock dividend
requirements of majority owned subsidiaries. "Preferred stock dividends" represent pretax
earnings which would be required to cover such dividend requirements.
</TABLE>
<PAGE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PG&E
CORPORATION AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL
STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 17,503
<OTHER-PROPERTY-AND-INVEST> 1,755
<TOTAL-CURRENT-ASSETS> 4,213
<TOTAL-DEFERRED-CHARGES> 3,180
<OTHER-ASSETS> 4,835
<TOTAL-ASSETS> 31,486
<COMMON> 5,373
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 2,397
<TOTAL-COMMON-STOCKHOLDERS-EQ> 7,770
780
0
<LONG-TERM-DEBT-NET> 6,759
<SHORT-TERM-NOTES> 624
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 424
<LONG-TERM-DEBT-CURRENT-PORT> 537
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 14,592
<TOT-CAPITALIZATION-AND-LIAB> 31,486
<GROSS-OPERATING-REVENUE> 16,457
<INCOME-TAX-EXPENSE> 365
<OTHER-OPERATING-EXPENSES> 15,069
<TOTAL-OPERATING-EXPENSES> 15,069
<OPERATING-INCOME-LOSS> 1,388
<OTHER-INCOME-NET> 80
<INCOME-BEFORE-INTEREST-EXPEN> 1,468
<TOTAL-INTEREST-EXPENSE> 584
<NET-INCOME> 519
0
<EARNINGS-AVAILABLE-FOR-COMM> 519
<COMMON-STOCK-DIVIDENDS> 330
<TOTAL-INTEREST-ON-BONDS> 252
<CASH-FLOW-OPERATIONS> 2,005
<EPS-BASIC> 1.41
<EPS-DILUTED> 1.40
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM PACIFIC GAS
AND ELECTRIC COMPANY AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH
FINANCIAL STATEMENTS.
</LEGEND>
<SUBSIDIARY>
<NUMBER> 1
<NAME> PACIFIC GAS AND ELECTRIC COMPANY
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 12,576
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 1,878
<TOTAL-DEFERRED-CHARGES> 3,041
<OTHER-ASSETS> 4,246
<TOTAL-ASSETS> 21,741
<COMMON> 1,607
<CAPITAL-SURPLUS-PAID-IN> 1,971
<RETAINED-EARNINGS> 1,966
<TOTAL-COMMON-STOCKHOLDERS-EQ> 5,544
437
287
<LONG-TERM-DEBT-NET> 5,025
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 77
<LONG-TERM-DEBT-CURRENT-PORT> 443
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 9,928
<TOT-CAPITALIZATION-AND-LIAB> 21,741
<GROSS-OPERATING-REVENUE> 6,905
<INCOME-TAX-EXPENSE> 424
<OTHER-OPERATING-EXPENSES> 5,545
<TOTAL-OPERATING-EXPENSES> 5,545
<OPERATING-INCOME-LOSS> 1,360
<OTHER-INCOME-NET> 30
<INCOME-BEFORE-INTEREST-EXPEN> 1,390
<TOTAL-INTEREST-EXPENSE> 450
<NET-INCOME> 516
18
<EARNINGS-AVAILABLE-FOR-COMM> 498
<COMMON-STOCK-DIVIDENDS> 290
<TOTAL-INTEREST-ON-BONDS> 252
<CASH-FLOW-OPERATIONS> 1,926
<EPS-BASIC> 0.00
<EPS-DILUTED> 0.00
</TABLE>
