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 March 31, 2000
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 May 9, 2000:
PG&E Corporation 385,326,805 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PG&E CORPORATION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2000
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: THE CALIFORNIA ELECTRIC INDUSTRY.................10
NOTE 3: RISK MANAGEMENT AND FINANCIAL INSTRUMENTS........17
NOTE 4: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED DEBENTURES...........20
NOTE 5: DIVESTITURES.....................................20
NOTE 6: COMMITMENTS AND CONTINGENCIES....................22
NOTE 7: SEGMENT INFORMATION..............................25
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS. ....................27
THE UTILITY...............................................29
PG&E NATIONAL ENERGY GROUP................................35
REGULATORY MATTERS........................................37
RESULTS OF OPERATIONS.....................................40
LIQUIDITY AND FINANCIAL RESOURCES.........................42
ENVIRONMENTAL MATTERS.....................................45
RISK MANAGEMENT ACTIVITIES................................45
LEGAL MATTERS.............................................46
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK.........................................47
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.........................................48
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.......48
ITEM 5. OTHER INFORMATION.........................................52
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................52
SIGNATURE..........................................................54
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
----------------------------------------------------
PG&E CORPORATION
STATEMENT OF CONDENSED CONSOLIDATED INCOME
(in millions, except per share amounts)
Three months ended March 31,
2000 1999 (1)
--------- ---------
Operating revenues
Utility $ 2,218 $ 2,085
Energy commodities and services 2,790 3,041
-------- --------
Total operating revenues 5,008 5,126
Operating expenses
Cost of energy for utility 796 655
Cost of energy commodities and services 2,472 2,797
Operating and maintenance, net 717 775
Depreciation, amortization and decommissioning 347 438
-------- --------
Total operating expenses 4,332 4,665
-------- --------
Operating income 676 461
Interest expense, net 183 201
Other income, net 15 21
-------- --------
Income before income taxes 508 281
Income taxes 228 114
-------- --------
Income from continuing operations 280 167
Discontinued operations
Loss from operations of PG&E Energy Services (net of
applicable income taxes of $7 million) - (8)
-------- --------
Income before cumulative effect of change
in accounting principle 280 159
Cumulative effect of change in accounting
principle (net of applicable income taxes
of $8 million) - 12
-------- --------
Net Income $ 280 $ 171
======== ========
Weighted Average Common Shares Outstanding 361 373
Earnings per common share, basic
Income from continuing operations $ .78 $ .45
Discontinued operations - (.02)
Cumulative effect of accounting change - .03
-------- --------
Net income $ .78 $ .46
======== ========
Earnings per common share, diluted
Income from continuing operations $ .77 $ .39
Discontinued operations - (.02)
Cumulative effect of accounting change - .03
-------- --------
Net income $ .77 $ .40
======== ========
Dividends declared per common share $ .30 $ .30
<FN>
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part
of this statement.
(1) Amounts have been restated to reflect the change in accounting for major maintenance and
overhauls at the PG&E National Energy Group (see Note 1 of the Notes to the Condensed
Consolidated Financial Statements), and reclassification of PG&E Energy Services operating
results to discontinued operations. The accounting change resulted in a cumulative effect being
recorded as of January 1, 1999, of $12 million ($0.03 per share), net of income taxes of $8
million. The accounting change did not have a material effect on operating expenses during the
first quarter of 1999. Operating income previously reported for the first quarter of 1999 was
$442 million. Net income previously reported for the first quarter of 1999 was $156 million
($0.42 per share).
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at March 31, December 31,
2000 1999
------------ -----------
ASSETS
Current assets
Cash and cash equivalents $ 260 $ 281
Short-term investments 45 187
Accounts receivable
Customers, net 1,459 1,486
Energy marketing 547 532
Price risk management 434 607
Inventories and prepayments 543 598
Deferred income taxes 111 133
-------- -------
Total current assets 3,399 3,824
Property, plant, and equipment
Utility 23,185 23,001
Non-utility
Electric generation 1,906 1,905
Gas transmission 2,549 2,541
Construction work in progress 458 436
Other 119 184
-------- -------
Total property, plant, and equipment (at original cost) 28,217 28,067
Accumulated depreciation and decommissioning (11,573) (11,291)
-------- --------
Net property, plant, and equipment 16,644 16,776
Other noncurrent assets
Regulatory assets 4,940 4,957
Nuclear decommissioning funds 1,300 1,264
Other 2,913 2,894
-------- --------
Total noncurrent assets 9,153 9,115
-------- --------
TOTAL ASSETS $ 29,196 $ 29,715
======== ========
<FN>
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part
of this statement.
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at March 31, December 31,
2000 1999
------------ ------------
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 952 $ 1,499
Current portion of long-term debt 672 592
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 619 708
Other 367 559
Regulatory balancing accounts 638 384
Energy marketing 594 480
Accrued taxes 529 211
Price risk management 391 575
Other 997 1,033
-------- --------
Total current liabilities 6,049 6,331
Noncurrent liabilities
Long-term debt 6,468 6,673
Rate reduction bonds 1,955 2,031
Deferred income taxes 3,011 3,147
Deferred tax credits 222 231
Other 3,624 3,636
-------- --------
Total noncurrent liabilities 15,280 15,718
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, 384,867,522 and 384,406,113 shares, respectively 5,916 5,906
Common stock held by subsidiary, at cost, 23,815,500 shares (690) (690)
Reinvested earnings 1,861 1,670
-------- --------
Total common stockholders' equity 7,087 6,886
Commitments and contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 29,196 $ 29,715
======== ========
<FN>
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part
of this statement.
PG&E CORPORATION
STATEMENT OF CONDENSED CONSOLIDATED CASH FLOWS (in millions)
For the three months ended March 31, 2000 1999
---------- ----------
Cash flows from operating activities
Net income $ 280 $ 171
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization and decommissioning 347 438
Deferred income taxes and tax credits-net (145) (178)
Other deferred charges and noncurrent liabilities (9) (125)
Cumulative effect of change in accounting principle - (12)
Net effect of changes in operating assets and liabilities:
Short-term investments 142 21
Accounts receivable - trade 12 333
Regulatory balancing accounts payable 254 212
Inventories and prepayments 55 97
Price risk management assets and liabilities, net (11) (20)
Accounts payable - trade (89) (167)
Accrued taxes 318 223
Other working capital (118) 101
Other-net 26 (69)
--------- ---------
Net cash provided by operating activities 1,062 1,025
--------- ---------
Cash flows from investing activities
Capital expenditures (321) (372)
Other-net 81 17
--------- ---------
Net cash used by investing activities (240) (355)
--------- ---------
Cash flows from financing activities
Net borrowings (repayments) under credit facilities (547) 161
Long-term debt matured, redeemed, or repurchased (201) (283)
Common stock issued 10 20
Common stock repurchased - (503)
Dividends paid (108) (115)
Other-net 3 9
--------- ---------
Net cash used by financing activities (843) (711)
--------- ---------
Net change in cash and cash equivalents (21) (41)
Cash and cash equivalents at January 1 281 286
--------- ---------
Cash and cash equivalents at March 31 $ 260 $ 245
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 117 $ 148
Income taxes(net of refunds) $ 3 $ (2)
<FN>
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part
of this statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONDENSED CONSOLIDATED INCOME (in millions)
Three months ended March 31,
2000 1999
--------- ---------
Electric utility $ 1,601 $ 1,533
Gas utility 617 552
-------- --------
Total operating revenues 2,218 2,085
Operating expenses
Cost of electric energy 513 409
Cost of gas 283 246
Operating and maintenance, net 551 626
Depreciation, amortization, and decommissioning 301 382
-------- --------
Total operating expenses 1,648 1,663
-------- --------
Operating income 570 422
Interest expense, net 141 154
Other income, net 5 11
-------- --------
Income before income taxes 434 279
Income taxes 200 126
-------- --------
Net income 234 153
Preferred dividend requirement 6 6
-------- --------
Income available for common stock $ 228 $ 147
======== ========
<FN>
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part
of this statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
March 31, December 31,
2000 1999
------------ -----------
ASSETS
Current assets
Cash and cash equivalents $ 87 $ 80
Short-term investments 23 21
Accounts receivable, net 1,126 1,210
Inventories 249 294
Prepayments 32 34
Deferred income taxes 109 119
--------- ---------
Total current assets 1,626 1,758
Property, plant, and equipment
Electric 15,840 15,762
Gas 7,345 7,239
Construction work in progress 217 214
--------- ---------
Total property, plant, and equipment (at original cost) 23,402 23,215
Accumulated depreciation and decommissioning (10,756) (10,497)
--------- ---------
Net property, plant, and equipment 12,646 12,718
Other noncurrent assets
Regulatory assets 4,879 4,895
Nuclear decommissioning funds 1,300 1,264
Other 906 835
-------- --------
Total noncurrent assets 7,085 6,994
-------- --------
TOTAL ASSETS $ 21,357 $ 21,470
======== ========
<FN>
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part
of this statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
March 31, December 31,
2000 1999
------------ -----------
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 209 $ 449
Current portion of long-term debt 549 465
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 468 577
Related parties 23 216
Regulatory balancing accounts 638 384
Other 323 333
Accrued taxes 344 118
Other 516 529
-------- -------
Total current liabilities 3,360 3,361
Noncurrent liabilities
Long-term debt 4,767 4,877
Rate reduction bonds 1,955 2,031
Deferred income taxes 2,471 2,510
Deferred tax credits 221 231
Other 2,269 2,252
------- -------
Total noncurrent liabilities 11,683 11,901
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 142 149
Common stock, $5 par value, authorized 800,000,000 shares,
issued 321,314,760 shares 1,606 1,606
Common stock held by subsidiary, at cost, 7,627,765 shares (200) (200)
Additional paid in capital 1,971 1,964
Reinvested earnings 2,213 2,107
-------- --------
Total stockholders' equity 5,877 5,771
Commitments and contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 21,357 $ 21,470
======== ========
<FN>
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part
of this statement.
PACIFIC GAS AND ELECTRIC COMPANY
STATEMENT OF CONDENSED CONSOLIDATED CASH FLOWS (in millions)
For the three months ended March 31, 2000 1999
----------- -----------
Cash flows from operating activities
Net income $ 234 $ 153
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization, and decommissioning 301 382
Deferred income taxes and tax credits-net (48) (194)
Other deferred charges and noncurrent liabilities (52) (4)
Net effect of changes in operating assets and liabilities:
Short-term investments (2) (1)
Accounts receivable 84 263
Regulatory balancing accounts payable 254 212
Inventories and prepayments 47 54
Accounts payable - trade (302) (179)
Accrued taxes 226 291
Other working capital (24) 117
Other-net (30) (2)
--------- ---------
Net cash provided by operating activities 688 1,092
--------- ---------
Cash flows from investing activities
Capital expenditures (265) (304)
Other-net 54 18
--------- ---------
Net cash used by investing activities (211) (286)
--------- ---------
Cash flows from financing activities
Net borrowings (repayments) under credit facilities (240) 258
Long-term debt matured, redeemed, or repurchased (102) (233)
Common stock repurchased - (725)
Dividends paid (122) (106)
Other-net (6) -
--------- ---------
Net cash used by financing activities (470) (806)
--------- ---------
Net change in cash and cash equivalents 7 -
Cash and cash equivalents at January 1 80 73
--------- ---------
Cash and cash equivalents at March 31 $ 87 $ 73
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 75 $ 91
Income taxes (net of refunds) $ - $ (3)
<FN>
The accompanying Notes to the Condensed Consolidated Financial Statements are an integral part
of this statement.
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY
NOTES TO CONDENSED 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 Condensed Consolidated Financial Statements
apply to both PG&E Corporation and the Utility. PG&E Corporation's condensed
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 condensed 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 1999 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 1999 Form 10-K was filed.
PG&E Corporation and the Utility believe that the accompanying condensed
consolidated 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 condensed
consolidated financial statements.
Certain amounts in the prior year's condensed consolidated financial
statements have been reclassified to conform to the 2000 presentation.
Results of operations for interim periods are not necessarily indicative of
results to be expected for a full year.
Effective January 1, 1999, PG&E Corporation changed its method of
accounting for major maintenance and overhauls at the PG&E National Energy
Group. Beginning January 1, 1999, the cost of major maintenance and
overhauls, principally at the PG&E Generating Company (PG&E Gen) business
segment, have been accounted for as incurred. Previously, the estimated cost
of major maintenance and overhauls was accrued in advance in a systematic and
rational manner over the period between major maintenance and overhauls. The
change resulted in PG&E Corporation recording income of $12 million net of
income tax ($0.03 per share), reflecting the cumulative effect of the change
in accounting principle. The effect on 1999 results of operations was
immaterial. The Utility consistently has accounted for major maintenance and
overhauls as incurred.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America 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: THE CALIFORNIA ELECTRIC INDUSTRY
In 1998, California became one of the first states in the country to
implement electric industry restructuring and establish a competitive market
framework for electric generation. Today, most Californians may continue to
purchase their electricity from investor-owned utilities such as Pacific Gas
and Electric Company, or they may choose to purchase electricity from
alternative generation providers (such as unregulated power generators and
unregulated retail electricity suppliers such as marketers, brokers, and
aggregators). For those customers who have not chosen an alternative
generation provider, investor-owned utilities, such as the Utility, continue
to be the generation providers. Investor-owned utilities continue to provide
distribution services to substantially all customers within their service
territories, including customers who choose an alternative generation
provider.
Competitive Market Framework
- ----------------------------
An Independent System Operator (ISO) and Power Exchange (PX) operate in
California to facilitate competition. The PX provides a competitive auction
process to establish market clearing prices for electricity in the markets
operated by the PX. 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. Unless
or until the California Public Utilities Commission (CPUC) determines
otherwise, 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, 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, unless the CPUC decides otherwise.
In November 1999, the Federal Energy Regulatory Commission (FERC) approved
the extension of the ISO's authority to establish price limitations through
2000. The ISO Board increased the applicable price limitation to $750 per
megawatt-hour (MWh) on October 1, 1999, but has the option to decrease it to
$500 per MWh or make other changes, in view of the FERC's decision. This
limits the amount of volatility that occurs in the California electricity
market. However, the ISO will review the appropriate level for any price
limitations for the summer of 2000 in light of market redesign efforts now
being considered, including changes to reduce uninstructed deviations from ISO
dispatch orders and changes to permit loads, to participate by submitting bids
for price responsive demand in energy or ancillary services markets.
For the quarters ended March 31, 2000 and 1999, 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:
March 31, March 31,
2000 1999
------------ -----------
(in millions)
Cost of fuel for electric generation and
qualifying facilities (QF) purchases $ 229 $ 371
Cost of purchases from the PX 196 152
Cost of ancillary services 203 110
Proceeds from sales to the PX (115) (224)
------------ -----------
$ 513 $ 409
============ ===========
Transition Period, Rate Freeze, and Rate Reduction
- --------------------------------------------------
California's electric industry restructuring established a transition
period during which electric rates remain frozen at 1996 levels (with the
exception that, on January 1, 1998, rates for small commercial and residential
customers were reduced by 10 percent and remain frozen at this reduced level)
and investor-owned utilities may recover their transition costs. Transition
costs are generation-related costs that prove to be uneconomic under the new
competitive structure. The transition period ends the earlier of December 31,
2001, or when the particular utility has recovered its eligible 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 competition transition charge (CTC), which
recovers the transition costs. These CTC revenues are being recovered from
all Utility distribution customers and are subject to seasonal fluctuations in
the Utility's sales volumes and certain other factors. As the CTC is
collected regardless of the customer's choice of electricity supplier (i.e.,
the CTC is non-bypassable), the Utility believes that the availability of
choice to its customers will not have a material impact on its ability to
recover transition costs.
To pay for the 10 percent rate reduction, the Utility refinanced $2.9
billion (the expected revenue reduction from the rate decrease) of its
transition costs with the proceeds from the 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 may
be obligated to return a portion of the economic benefits of the transaction
to customers. The timing of any such return and the exact amount of such
portion, if any, have not yet been determined.
Transition Cost Recovery
- ------------------------
Although most transition costs must be recovered during the transition
period, certain transition costs can be recovered after the transition period.
Except for certain transition costs discussed below, 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 generating facilities that are fixed and unavoidable and that
were included in customers' rates on December 20, 1995) and future sunk costs,
such as costs related to plant removal, (2) costs associated with 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 exceeds
its market value. Conversely, below-market sunk costs result when the market
value of a facility exceeds its book value. The total amount of generation
facility costs to be included as transition costs is 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 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 the valuation of
the Utility's remaining non-nuclear generating assets, primarily its
hydroelectric generating assets, is completed. The valuation, through
appraisal, sale, or other divestiture, must be completed by December 31, 2001.
The value of seven of the Utility's other non-nuclear generating facilities
was determined when these facilities were sold to third parties. The portion
of the sales proceeds that exceeded the book value of these facilities was
used to reduce other transition costs. 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. (See "Generation Divestiture" below.) 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. 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.)
For nuclear transition costs, revenues provided for transition cost
recovery are based on the accelerated recovery of the investment in Diablo
Canyon Nuclear Power Plant (Diablo Canyon) over a five-year period ending
December 31, 2001. The amount of nuclear generation sunk costs was determined
separately through a CPUC proceeding and was subject to a final verification
audit that was completed in August 1998. The audit of the Utility's 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 the results of the audit and
may seek to make adjustments to Diablo Canyon's sunk costs subject to
transition cost recovery. In May 2000, the Utility filed a petition at the
CPUC to close out the audit report without any changes in rates. The petition
is not opposed by the two consumer advocacy groups who originally requested
the audit, the Commission's Office of Ratepayer Advocates (ORA) and The
Utility Reform Network (TURN). 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 are included as transition costs. Regulation required the
Utility to enter into such long-term agreements with non-utility generators.
Prices fixed under these contracts are now typically above prices for power in
wholesale markets. Over the remaining life of these contracts, the Utility
estimates that it will purchase 299 million MWh 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 costs under long-term contracts are based on several variables,
including the capacity factors of the related generating facilities and future
market prices for electricity. For the three months ended March 31, 2000 and
1999, the average price paid under the Utility's long-term contracts for
electricity was 5.3 cents and 5.5 cents per kilowatt-hour (kWh), respectively.
The average cost of electricity purchased at market rates from the PX for the
three months ended March 31, 2000 and 1999, was 3.6 cents and 2.3 cents per
kWh, respectively.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At March 31,
2000 and December 31, 1999, the Utility's generation-related net regulatory
assets totaled $4.0 billion.
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 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 will 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 Utility customers' electric rates. Excluding
these exceptions, the Utility will write off any transition costs not
recovered during the transition period.
The Utility is amortizing its transition costs, including most generation-
related regulatory assets, over the transition period in conjunction with the
available CTC revenues. During the transition period, a reduced rate of
return on common equity of 6.77 percent applies to all generation assets,
including those generation assets reclassified to regulatory assets.
Effective January 1, 1998, the Utility started collecting these eligible
transition costs through the non-bypassable CTC and generation divestiture.
Regulatory assets related to electric industry restructuring increased by $15
million for the quarter ended March 31, 2000, and decreased $247 million for
the quarter ended March 31, 1999.
During the transition period, the CPUC reviews the Utility's compliance
with accounting methods established in the CPUC's decisions governing
transition cost recovery and the amount of transition costs requested for
recovery. In February 2000, the CPUC approved substantially all non-nuclear
transition costs that were amortized during the first six months of 1998. The
CPUC is currently reviewing non-nuclear transition costs amortized from July
1, 1998, to June 30, 1999.
Generation Divestiture
- ----------------------
In 1998, the Utility sold 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 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.
The Utility has retained a liability for required environmental remediation
related to any pre-closing soil or groundwater contamination at the plants it
has sold.
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, the PG&E National Energy Group
would be permitted to participate in the auction on the same basis as other
bidders.
The sale of the hydroelectric facilities would be subject to certain
conditions, including the transfer or re-issuance of various permits and
licenses by the FERC and other agencies. In addition, the 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 the Utility's sole discretion is also a condition precedent to the
closing of any sale.
The CPUC has ordered that the proceeding be divided into two concurrent
phases: one to review the potential environmental impacts of the proposed
auction under the California Environmental Quality Act and a second to
determine whether the Utility's auction proposal, or some other alternative to
the proposal, is in the public interest. The ruling sets a procedural
schedule that calls for a final decision on the Utility's auction proposal by
October 19, 2000, and a final environmental impact report published in
November 2000. The ruling also anticipates that a final CPUC decision
approving the sale would be issued by May 15, 2001. Finally, the ruling
prohibits the Utility from withdrawing its application without express CPUC
authority. It is uncertain whether the CPUC will ultimately approve the
Utility's auction proposal.
On February 17, 2000, the CPUC issued a decision in another proceeding, the
1998 Annual Transition Cost Proceeding (ATCP), that requires California
investor-owned utilities to estimate the market value of their remaining non-
nuclear generating assets, including the land associated with those assets, at
a value not less than the net book value of those assets on an aggregate basis
and to credit the Transition Cost Balancing Account (TCBA) with the estimated
value. The decision encourages the utilities to base such estimates on
realistic assessments of the market value of the assets. The decision
provides that if the estimated market valuation is less than book value for
any individual asset, accelerated amortization of the associated transition
costs will continue until final market valuation of the asset occurs through
sale, appraisal, or other divestiture. If the final value of the assets,
determined through sale, appraisal, or other divestiture, is higher than the
estimate, the excess amount would be used to reduce remaining transition
costs, if any. The utilities are required to file the adjusted entries to
their respective TCBA based on the estimated market values with the CPUC by
May 31, 2000. The filing will become effective after appropriate review by
the CPUC's Energy Division and will be subject to review in the next ATCP. On
May 2, 2000, a proposed decision was issued recommending the establishment of
an accounting mechanism to permit a regulatory asset to be recorded equal to
the amount credited to the TCBA. If an estimate of the market value of the
non-nuclear generating assets is adopted that exceeds the aggregate net book
value of those assets, and if an appropriate accounting mechanism is not
adopted, a charge to earnings would result.
At March 31, 2000, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.7 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory
assets. Any excess of market value over the $0.7 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 the PG&E National Energy Group, 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. As discussed above, it is possible that the
CPUC will require an interim valuation through an estimate of market value of
the assets prior to transfer, sale or other divestiture, which could also
result in a material charge. While transfer or sale to an affiliated entity
such as the PG&E National Energy Group would result in a material charge to
income, neither PG&E Corporation nor the Utility believes that the sale of any
generation facilities to a third party will have a material impact on its
results of operations.
The Utility's ability to continue recovering its transition costs depends
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, and
(6) the market price of electricity. Given the current evaluation of these
factors, PG&E Corporation believes that the Utility will recover its
transition costs. 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.
Post-Transition Period
- ----------------------
The timing of the end of the rate freeze and corresponding transition
period will, in part, depend on the timing of the valuation of the Utility's
hydroelectric generating assets and the ultimate determined value of such
assets since any excess of market value over the assets' book value would be
used to reduce transition costs. If the value of the Utility's hydroelectric
generation assets is significantly higher than the related book value, the
transition period and the rate freeze could end before December 31, 2001, and
potentially could end during 2000.
In October 1999, the CPUC issued a decision in the Utility's post-
transition period ratemaking proceeding. Among other matters, the CPUC's
decision addresses the mechanisms for ending the current electric rate freeze
and for establishing post-transition period accounting mechanisms and rates.
The decision prohibits the Utility from continuing to price electric
generation from Diablo Canyon based on the incremental cost incentive price
(ICIP) after the transition period has ended. The ICIP, which has been in
place since January 1, 1997, is a performance-based mechanism that establishes
a rate per kilowatt-hour (kWh) generated by the facility. The ICIP prices for
1999, 2000, and 2001 are 3.37 cents per kWh, 3.43 cents per kWh, and 3.49
cents per kWh, respectively. The average price for base load electric energy
(the price received for a constant level of electric generation for all hours
of electric demand) sold at market rates to the California PX for the three-
month periods ended March 31, 2000 and 1999, was 3.6 cents and 2.3 cents per
kWh, respectively. The average price for base load electric energy sold at
market rates to the California PX for the 12 months ending March 31, 2000 was
4.0 cents per kWh. Future market prices may be higher or lower. Under the
CPUC's decision, after the transition period, the Utility must price Diablo
Canyon generation at the prevailing market price for power.
The CPUC decision requires the Utility to provide quarterly forecasts of
when the Utility's rate freeze (i.e., transition period) may end based on
various assumptions regarding energy prices and the market value of the
Utility's remaining generation assets. The Utility is required to notify the
CPUC three months before the earliest forecasted end of its rate freeze and
provide draft tariff language and sample calculations of the rates that would
go into effect when the rate freeze ends. After the Utility completes its
transition cost recovery, it must implement its post-rate-freeze rates.
After the rate freeze and transition periods end, the Utility must refund
to electric customers any over-collected transition costs (plus interest at
the Utility's three-month commercial paper rate) within one year after the end
of the rate freeze. The Utility also will be prohibited from collecting after
the rate freeze certain electric costs incurred during the rate freeze but not
recovered during the rate freeze, including costs that are not classified as
transition costs and are not related to generation assets such as under-
collected accounting balances relating to power purchases. Through the end of
its rate freeze, the Utility will continue to incur certain non-transition
costs and place those costs into balancing and memorandum accounts for future
recovery. There is a risk that the Utility will be unable to collect certain
non-transition costs that, due to lags in the regulatory cost approval
process, have not been approved for recovery nor collected when the rate
freeze ends. The Utility is unable to predict the amount of such potential
unrecoverable costs.
In November 1999, the Utility filed an application for rehearing of the
CPUC's decision. In March 2000, the CPUC denied the Utility's application for
rehearing on the issues of Diablo Canyon ICIP and post-transition period
recovery of non-transition costs. On April 17, 2000, the Utility filed a
petition for review in the California Court of Appeal on the issue of post-
transition period recovery of non-transition costs.
The CPUC also has established the Purchased Electric Commodity Account
(PECA) for the Utility to track energy costs after the rate freeze and
transition period end. The CPUC intends to explore other ratemaking issues,
including whether dollar-for-dollar recovery of energy costs is appropriate,
in the second phase of the post-transition period electric ratemaking
proceeding. There are three primary options for the future regulatory
framework for utility electric energy procurement cost recovery after the rate
freeze: (1) a CPUC-defined procurement practice, that if followed by the
Utility, would pass through costs without the need for reasonableness reviews,
(2) a pass-through of costs subject to after-the-fact reasonableness reviews,
or (3) a procurement incentive mechanism with rewards and penalties determined
based on the Utility's energy purchasing performance compared to a benchmark.
The Utility proposed adoption of either a defined procurement practice or a
procurement incentive mechanism, neither of which would involve reasonableness
reviews. On March 17, 2000, the CPUC issued a proposed decision that states
that after the rate freeze, there will be two electric rate proceedings to
address electric energy procurement practices and rates. The Revenue
Adjustment Proceeding (RAP) will be a forecast of costs, and the ATCP will
include a review of procurement costs to the extent costs above the wholesale
PX rate are included in the PECA. The volatility of earnings and risk
exposure of the Utility related to post-transition period purchases of
electricity is dependent on which of these options, or some other approach, is
adopted.
Further, pursuant to the 1997 CPUC decision establishing the ICIP, the
Utility is required to begin sharing 50 percent of the net benefits of
operating Diablo Canyon with ratepayers at the end of the transition period.
The Utility is required to file an application by July 2000 with its proposal
for the methods to be used in the valuation of the benefits associated with
the operation of Diablo Canyon, and the mechanism to be used to share these
benefits with ratepayers. The Utility and PG&E Corporation are unable to
predict what type of valuation and sharing mechanism will be adopted and what
the ultimate financial impact of the sharing mechanism will have on results of
operations or financial position.
The ultimate financial impact of the post-transition period issues
discussed above will depend on the date the Utility's transition cost recovery
is completed and the rate freeze ends, future costs including Diablo Canyon
operating costs, future market prices for electricity, the method adopted by
the CPUC for sharing net benefits of operating Diablo Canyon with ratepayers,
the amount of any electric non-transition costs that have been incurred but
not recovered as of the end of the rate freeze, the timing of various
regulatory proceedings in which the Utility seeks approval for rate recovery
of various costs incurred during the rate freeze, and other variables that
PG&E Corporation and the Utility are unable to predict.
After the transition period, the Utility's future earnings from its
electric distribution will be subject to volatility due to sales fluctuations.
NOTE 3: 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 risk management as of March 31, 2000 and 1999. Short and
long positions pertaining to derivative contracts used for hedging activities
as of March 31, 2000 and 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 - March 31, 2000
Swaps 1.74 1.66 7
Options 0.80 0.83 8
Futures 0.10 0.11 2
Forward Contracts 2.22 13.00 11
Non-Hedging Activities - March 31, 1999
Swaps 3.83 3.65 8
Options 1.08 0.99 5
Futures 0.55 0.57 3
Forward Contracts 2.62 2.67 9
(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 quarters ended March 31, 2000 and 1999, are
as follows:
March 31, March 31,
2000 1999
--------- ---------
(in millions)
Swaps $ (23) $ 235
Options 62 15
Futures 37 (9)
Forward contracts (31) (203)
------- -------
Net gain $ 45 $ 38
======= =======
The following table discloses the estimated fair values of risk management
assets and liabilities as of March 31, 2000 and December 31, 1999. The ending
and average fair values and associated carrying amounts of derivative
contracts used for hedging purposes are not material as of March 31, 2000 and
December 31, 1999.
Average Ending
Fair Value Fair Value
- ---------------------------------------------------------------------------
(in millions)
Non-hedging activities - March 31, 2000
Assets
Swaps $ 146 $ 48
Options 90 87
Futures 27 7
Forward Contracts 590 614
------ ------
Total $ 853 $ 756
Noncurrent portion $ 322
Current portion $ 434
Liabilities
Swaps $ 130 $ 42
Options 61 40
Futures 39 12
Forward Contracts 502 547
------ ------
Total $ 732 $ 641
Noncurrent portion $ 250
Current portion $ 391
Non-hedging activities - December 31, 1999
Assets
Swaps $ 643 $ 244
Options 106 92
Futures 175 47
Forward Contracts 667 596
------ ------
Total $1,591 $ 979
Noncurrent portion $ 372
Current portion $ 607
Liabilities
Swaps $ 592 $ 218
Options 109 81
Futures 201 67
Forward Contracts 561 456
------ ------
Total $1,463 $ 822
Noncurrent portion $ 247
Current portion $ 575
PG&E Corporation, primarily through its subsidiaries, engages in risk
management activities for both non-hedging and hedging purposes. Non-hedging
activities are conducted principally through its unregulated subsidiary, PG&E
Energy Trading (PG&E ET). In compliance with regulatory requirements, the
Utility manages risk independently from the activities in PG&E Corporation's
unregulated businesses (see Note 1 for further discussion). The Utility
primarily engages in hedging activities which were immaterial for the three
month periods ended March 31, 2000 and 1999.
In valuing its electric power, natural gas, and natural gas liquids
portfolios, PG&E Corporation considers a number of market risks and estimated
costs and continuously monitors the valuation of identified risks and adjusts
them based on present market conditions. Considerable judgment is required to
develop the estimates of fair value; thus, the estimates provided herein are
not necessarily indicative of the amounts that PG&E Corporation could realize
in the current market.
Generally, exchange-traded futures contracts require deposit of margin
cash, the amount of which is subject to change based on market movement and in
accordance with exchange rules. Margin cash requirements for over-the-counter
financial instruments are specified by the particular instrument and often do
not require margin cash and are settled monthly. Both exchange-traded and
over-the-counter options contracts require payment/receipt of an option
premium at the inception of the contract. Margin cash for commodities futures
and cash on deposit with counterparties was $22 million at March 31, 2000.
The credit exposure of the five largest counterparties comprised
approximately $326 million of the total credit exposure associated with
financial instruments used to manage price risk. Counterparties considered to
be investment grade or higher comprise 88 percent of the total credit
exposure.
NOTE 4: 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 5: DIVESTITURES
In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E Energy Services (PG&E ES), its wholly owned subsidiary,
through a sale. In December 1999, the intended disposal was accounted for as
a discontinued operation. In connection with this transaction, PG&E
Corporation's investment in PG&E ES was written down to its estimated net
realizable value. In addition, PG&E Corporation provided a reserve for
anticipated losses through the date of sale. The total provision for
discontinued operations was $58 million, net of income taxes of $36 million.
During the three-month period ended March 31, 2000, $14.7 million was charged
against this reserve. On April 12, 2000, the PG&E National Energy Group
signed an agreement to sell specified assets, liabilities, and contracts of
PG&E Energy Services Corporation. The consideration to be received by the
PG&E National Energy Group is $20 million, plus net working capital of
approximately $65 million, for a total of $85 million. The transaction is
expected to close by June 2000. The remaining components of PG&E Energy
Services Corporation, mainly the Value Added Services business and various
other assets, will continue to be offered for sale. The PG&E National Energy
Group expects to complete this disposition prior to year-end 2000. The
disposition of PG&E ES has been reflected in the financial statements as a
discontinued operation. The PG&E ES business segment generated net losses of
$8 million (or $0.02 per share), for the three month period ended March 31,
1999.
The total assets and liabilities, including the charge noted above, of
PG&E ES included in the PG&E Corporation Consolidated Balance Sheet at March
31, 2000 and December 31, 1999 are as follows:
March 31, December 31,
2000 1999
----------- -----------
(in millions)
Assets
Current assets $ 83 $ 114
Noncurrent assets 88 83
----- -----
Total Assets 171 197
Liabilities
Current liabilities 40 61
Noncurrent liabilities 9 10
----- -----
Total Liabilities 49 71
----- -----
Net Assets $ 122 $ 126
===== =====
On January 27, 2000, the PG&E National Energy Group signed a definitive
agreement with El Paso Field Services Company (El Paso) providing for the
sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of
PG&E Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc.
(collectively, PG&E GT-Texas). The consideration to be received by the PG&E
National Energy Group includes $279 million in cash subject to a working
capital adjustment, the assumption by El Paso of debt having value of $624
million, and other liabilities associated with PG&E GT-Texas.
In 1999, PG&E Corporation recognized a charge against earnings of $890
million after-tax as follows: (1) an $819 million write down of net
property, plant, and equipment, (2) the elimination of the unamortized
portion of goodwill, in the amount of $446 million, and (3) an accrual of $10
million representing selling costs.
Proceeds from the sale will be used to retire short-term debt associated
with PG&E GT-Texas' operations and for other corporate purposes. Closing of
the sale, which is expected in the first half of 2000, is subject to approval
under the Hart-Scott-Rodino Act.
The sale of PG&E GT-Texas represents disposal of the PG&E GTT business
segment and a portion of the PG&E ET business segment. PG&E GT-Texas' total
assets and liabilities, including the charge noted above, included in the
PG&E Corporation Consolidated Balance Sheet at March 31, 2000 and December
31, 1999, are as follows:
March 31, December 31,
2000 1999
----------- -----------
(in millions)
Assets
Current assets $ 209 $ 229
Noncurrent assets 974 988
----- -----
Total Assets 1,183 1,217
Liabilities
Current liabilities 458 448
Noncurrent liabilities 578 624
----- -----
Total Liabilities 1,036 1,072
----- -----
Net Assets $ 147 $ 145
===== =====
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 $15 million (property damage) and $4 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 $9.3 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
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 the Utility for the storage
or disposal of potentially hazardous materials. Under federal and California
laws, the Utility 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 clean-up 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. At March 31, 2000, the Utility expects to spend $303
million for hazardous waste remediation costs at identified sites, including
divested fossil-fueled power plants. The Utility had an accrued liability of
$275 million and $271 million at March 31, 2000 and December 31, 1999,
respectively, representing the discounted value of these costs.
Of the $275 million accrued liability discussed above, the Utility has
recovered $148 million through rates, including $34 million through
depreciation, and expects to recover another $99 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 $501
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 clean-up costs at additional sites or outcomes change.
Further, as discussed in "Generation Divestiture" in Note 2, 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
court. The suits seek an unspecified amount of compensatory and punitive
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 900 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 adverse impact on its or the Utility's financial position
or results of operations.
Texas Franchise Fee Litigation:
In connection with PG&E Corporation's acquisition of Valero Energy
Corporation, now known as PG&E Gas Transmission Texas Corporation (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 five 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.
In connection with the certification of a class in one of the class
actions, the court ordered notice to be sent to all potential class members
and setting an opt-out deadline of December 31, 1997. Notices were mailed to
approximately 159 Texas cities. Fewer than 20 cities opted out by the
deadline. In November 1999, the court signed an order dismissing from the
class 42 cities because it determined there was no pipeline presence and no
past or present sales activity, leaving 106 cities in the class. A settlement
proposal has been presented to the court. On January 27, 2000, the court
approved the settlement proposal and established a 14-day period whether to
accept the negotiated settlement terms or opt out of the settlement. The Court
also stated that if Corpus Christi does not accept the settlement proposal, it
will be placed in a sub-class, whose claims will not be finalized as part of
the settlement approval. Corpus Christi has the right to opt out of this
subclass. The settlement proposal contemplates, among other things, that the
PG&E Corporation defendants would pay a total of not more than $12.2 million
to the settling class cities, inclusive of attorney fees, reduced by amounts
attributable to opt-out cities. The defendants retain the right to reject the
settlement if the settlement proposal is not approved by certain key cities
and by 80 percent of the plaintiff class. Although a significant number of
the 106 cities in the plaintiff class already have either approved the
settlement by enacting the ordinance, or adopted resolutions to pass the
ordinance, certain key cities and other cities have not approved the
settlement and have opted out of the settlement. Corpus Christi has opted out
of the general settlement, but is continuing to negotiate a possible sub-class
settlement with representatives of the class defendants. Representatives of
the class defendants and class counsel are negotiating changes to the
settlement. The settlement is also subject to final court approval.
PG&E Corporation believes that the ultimate outcome of these matters will
not have a material adverse impact on its financial position or its results of
operations. In January 2000, PG&E Corporation's National Energy Group signed
a definitive agreement to sell the stock of PG&E Gas Transmission, Texas
Corporation and PG&E Gas Transmission Teco, Inc. The buyer will assume all
liabilities associated with the cases described above.
Recorded Liability for Legal Matters:
In accordance with SFAS No. 5, PG&E Corporation makes a provision for a
liability when both it is probable that a liability has been incurred and the
amount of the loss can be reasonably estimated. These provisions are reviewed
quarterly and adjusted to reflect the impacts of negotiations, settlements,
rulings, advice of legal counsel, and other information and events pertaining
to a particular case. The following table reflects the current year's
activity to the recorded liability for legal matters:
PG&E
Corporation Utility
------------ -----------
(in millions)
Beginning balance, January 1, 2000 $ 125 $ 69
Provisions for liabilities 1 1
Payments (4) (4)
Adjustments - -
----- -----
Ending balance, March 31, 2000 $ 122 $ 66
===== =====
NOTE 7: SEGMENT INFORMATION
PG&E Corporation has identified four reportable operating segments. The
Utility is one reportable operating segment and the other three are part of
the PG&E National Energy Group. These four 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.
PG&E National Energy Group: The PG&E National Energy Group businesses
develop, construct, operate, own, and manage independent power generation
facilities that serve wholesale and industrial customers through PG&E
Generating Company, LLC and its affiliates (collectively, PG&E Gen); own and
operate natural gas pipelines, natural gas storage facilities, and natural gas
processing plants, primarily in the Pacific Northwest and in Texas, through
various subsidiaries of PG&E Corporation (collectively, PG&E Gas Transmission
or PG&E GT); and purchase and sell energy commodities and provide risk
management services to customers in major North American markets, including
the other PG&E National Energy Group non-utility businesses, unaffiliated
utilities, marketers, municipalities, and large end-use customers through PG&E
Energy Trading - Gas Corporation, PG&E Energy Trading - Power, L.P., and their
affiliates (collectively, PG&E Energy Trading or PG&E ET). In the fourth
quarter of 1999, PG&E Corporation's Board of Directors approved a plan for the
divestiture of PG&E Corporation's Texas natural gas and natural gas liquids
business. Also in the fourth quarter of 1999, PG&E Corporation's Board of
Directors approved a plan for the divestiture of PG&E Corporation's retail
energy services, conducted through PG&E ES.
Segment information for the three months ended March 31, 2000 and 1999,
respectively, was as follows:
Utility PG&E National Energy Group
------- -------------------------------------------
PG&E GT Elimi-
---------------- nations &
PG&EGen NW Texas PG&E ET Other (1) Total
------- ------- ------- ------- ------- -------
(in millions)
March 31, 2000
Operating revenues $ 2,214 $ 310 $ 45 $ 212 $2,237 $ (10) $ 5,008
Intersegment revenues 4 2 12 13 320 (351) -
------- ------- ------- ------- ------- ------- -------
Total operating revenues 2,218 312 57 225 2,557 (361) 5,008
Income from
continuing operations 228 35 14 - 11 (8) 280
Total assets at quarter end 21,357 3,865 1,149 1,183 1,886 (244) 29,196
March 31, 1999
Operating revenues $ 2,083 $ 288 $ 46 $ 313 $ 2,396 $ - $ 5,126
Intersegment revenues 2 1 12 44 235 (294) -
------- ------- ------- ------- ------- ------- -------
Total operating revenues 2,085 289 58 357 2,631 (294) 5,126
Income from
continuing operations 147 32 15 (24) (3) - 167
Total assets at quarter end 22,455 3,831 1,165 2,643 4,014 - 34,108
<FN>
(1) Net income on intercompany positions recognized by segments using mark-to-market accounting
is eliminated. Intercompany transactions are also eliminated.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS
---------------------------------------------
PG&E Corporation is an energy-based holding company headquartered in San
Francisco, California. 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. The
PG&E National Energy Group provides energy products and services throughout
North America.
The PG&E National Energy Group businesses develop, construct, operate, own,
and manage independent power generation facilities that serve wholesale and
industrial customers through PG&E Generating Company, LLC (and its affiliates
(collectively, PG&E Gen); own and operate natural gas pipelines, natural gas
storage facilities, and natural gas processing plants, primarily in the
Pacific Northwest and in Texas, through various subsidiaries of PG&E
Corporation (collectively, PG&E Gas Transmission or PG&E GT); purchase and
sell energy commodities and provide risk management services to customers in
major North American markets, including the other PG&E National Energy Group
non-utility businesses, unaffiliated utilities, marketers, municipalities, and
large end-use customers through PG&E Energy Trading-Gas Corporation, PG&E
Energy Trading-Power, L.P., and their affiliates (collectively, PG&E Energy
Trading or PG&E ET); and provide competitively priced electricity, natural
gas, and related services to industrial, commercial, and institutional
customers through PG&E Energy Services Corporation (PG&E Energy Services or
PG&E ES). PG&E Corporation has entered into an agreement to sell its Texas
natural gas and natural gas liquids business. PG&E Corporation also has
entered into an agreement to sell the stock of PG&E ES, through which the
buyer will acquire PG&E ES' retail electric and gas commodities business.
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 wholly owned and controlled subsidiaries. The consolidated
financial statements of the Utility reflect the accounts of the Utility and
its wholly owned and controlled 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 1999 Annual Report on Form 10-K.
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 current
expectations and assumptions 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," and other similar expressions. Actual
results could differ materially from those contemplated by the forward-looking
statements.
Factors that could cause future results to differ materially from those
expressed in or implied by the forward-looking statements or historical
results include:
- regulatory changes, including the pace and extent of the ongoing
restructuring of the electric and natural gas industries across the United
States;
- operational changes related to industry restructuring, including changes
in the Utility's business processes and systems;
- the method and timing of disposition and valuation of the Utility's
hydroelectric generation assets;
- the timing of the completion of the Utility's transition cost recovery and
the consequent end of the current electric rate freeze in California;
- any changes in the amount of transition costs the Utility is allowed to
collect from its customers;
- future operating performance at the Diablo Canyon Nuclear Power Plant
(Diablo Canyon);
- the method adopted by the California Public Utilities Commission (CPUC)
for sharing the net benefits of operating Diablo Canyon with ratepayers and
the timing of the implementation of the adopted method;
- the extent of anticipated growth of transmission and distribution services
in the Utility's service territory;
- future market prices for electricity;
- future fuel prices;
- future weather conditions;
- the success of management's strategies to maximize shareholder value in
the PG&E National Energy Group, which may include acquisitions or dispositions
of assets, or internal restructuring;
- the extent to which our current or planned generation development projects
are completed and the pace and cost of such completion;
- generating capacity expansion and retirements by others;
- the successful integration and performance of acquired assets;
- the outcome of the Utility's various regulatory proceedings, including the
proposal to auction the Utility's hydroelectric generation assets, the
electric transmission rate case applications, and post-transition period
ratemaking proceedings;
- fluctuations in commodity gas, natural gas liquids, and electric prices
and our ability to successfully manage such price fluctuations;
- 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;
- the effect of compliance with existing and future environmental laws,
regulations, and policies; the cost of which could be significant; and
- the outcome of pending litigation.
As the ultimate impact of these and other factors is 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
quarters ended March 31, 2000 and 1999. 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.
THE UTILITY
Transition Period, Rate Freeze, and Rate Reduction
- --------------------------------------------------
California's electric industry restructuring established a transition
period during which electric rates remain frozen at 1996 levels (with the
exception that, on January 1, 1998, rates for small commercial and residential
customers were reduced by 10 percent and remain frozen at this reduced level)
and investor-owned utilities may recover their transition costs. Transition
costs are generation-related costs that prove to be uneconomic under the new
competitive structure. The transition period ends the earlier of December 31,
2001, or when the particular utility has recovered its eligible 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 being recovered from
all Utility distribution customers and are subject to seasonal fluctuations in
the Utility's sales volumes and certain other factors. As the CTC is
collected regardless of the customer's choice of electricity supplier (i.e.,
the CTC is non-bypassable), the Utility believes that the availability of
choice to its customers will not have a material impact on its ability to
recover transition costs.
Transition Cost Recovery
- ------------------------
Although most transition costs must be recovered during the transition
period, certain transition costs can be recovered after the transition period.
Except for certain transition costs discussed below, 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 generating facilities that are fixed and unavoidable and that
were included in customers' rates on December 20, 1995) and future sunk costs,
such as costs related to plant removal, (2) costs associated with long-term
contracts to purchase power at above-market prices from qualifying facilities
(QF) 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 exceeds
its market value. Conversely, below-market sunk costs result when the market
value of a facility exceeds its book value. The total amount of generation
facility costs to be included as transition costs is 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 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 the valuation of
the Utility's remaining non-nuclear generating assets, primarily its
hydroelectric generating assets, is completed. The valuation, through
appraisal, sale, or other divestiture, must be completed by December 31, 2001.
The value of seven of the Utility's other non-nuclear generating facilities
was determined when these facilities were sold to third parties. The portion
of the sales proceeds that exceeded the book value of these facilities was
used to reduce other transition costs. 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. (See "Generation Divestiture" below.) 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. 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.)
For nuclear transition costs, revenues provided for transition cost
recovery are based on the accelerated recovery of the investment in Diablo
Canyon over a five-year period ending December 31, 2001. The amount of
nuclear generation sunk costs was determined separately through a CPUC
proceeding and was subject to a final verification audit that was completed in
August 1998. The audit of the Utility's 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 the results of the audit and may seek to make adjustments to Diablo
Canyon's sunk costs subject to transition cost recovery. In May 2000, the
Utility filed a petition at the CPUC to close out the audit report without any
changes in rates. The petition is not opposed by the two consumer advocacy
groups who originally requested the audit, the Commission's Office of
Ratepayer Advocates (ORA) and The Utility Reform Network (TURN). 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 are included as transition costs. Regulation required the
Utility to enter into such long-term agreements with non-utility generators.
Prices fixed under these contracts are now typically above prices for power in
wholesale markets. Over the remaining life of these contracts, the Utility
estimates that it will purchase 299 million MWh 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 costs under long-term contracts are based on several variables,
including the capacity factors of the related generating facilities and future
market prices for electricity. For the three months ended March 31, 2000 and
1999, the average price paid under the Utility's long-term contracts for
electricity was 5.3 cents and 5.5 cents per kilowatt-hour (kWh), respectively.
The average cost of electricity purchased at market rates from the California
Power Exchange (PX) for the three months ended March 31, 2000 and 1999, was
3.6 cents and 2.3 cents per kWh, respectively.
Generation-related regulatory assets and obligations (net generation-
related regulatory assets) are included as transition costs. At March 31,
2000 and December 31, 1999, the Utility's generation-related net regulatory
assets totaled $4.0 billion.
The Utility is amortizing its transition costs, including most generation-
related regulatory assets, over the transition period in conjunction with the
available CTC revenues. During the transition period, a reduced rate of
return on common equity of 6.77 percent applies to all generation assets,
including those generation assets reclassified to regulatory assets.
Effective January 1, 1998, the Utility started collecting these eligible
transition costs through the non-bypassable CTC and generation divestiture.
Regulatory assets related to electric industry restructuring increased by $15
million for the quarter ended March 31, 2000, and decreased $247 million for
the quarter ended March 31, 1999.
Generation Divestiture
- ----------------------
On April 16, 1999, the Utility sold three 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 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.
The Utility has retained a liability for required environmental remediation
related to any pre-closing soil or groundwater contamination at the plants it
has sold.
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, the PG&E National Energy Group
would be permitted to participate in the auction on the same basis as other
bidders.
The sale of the hydroelectric facilities would be subject to certain
conditions, including the transfer or re-issuance of various permits and
licenses by the Federal Energy Regulatory Commission (FERC) and other
agencies. In addition, the FERC must approve assignment of the Utility's
Reliability Must Run Contract with the Independent System Operator (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 the Utility's sole discretion is also a condition precedent to the
closing of any sale.
The CPUC has ordered that the proceeding be divided into two concurrent
phases: one to review the potential environmental impacts of the proposed
auction under the California Environmental Quality Act and a second to
determine whether the Utility's auction proposal, or some other alternative to
the proposal, is in the public interest. The ruling sets a procedural
schedule that calls for a final decision on the Utility's auction proposal by
October 19, 2000, and a final environmental impact report published in
November 2000. The ruling also anticipates that a final CPUC decision
approving the sale would be issued by May 15, 2001. Finally, the ruling
prohibits the Utility from withdrawing its application without express CPUC
authority. It is uncertain whether the CPUC will ultimately approve the
Utility's auction proposal.
On February 17, 2000, the CPUC issued a decision in another proceeding, the
1998 Annual Transition Cost Proceeding (ATCP), that requires California
investor-owned utilities to estimate the market value of their remaining non-
nuclear generating assets, including the land associated with those assets, at
a value not less than the net book value of those assets on an aggregate basis
and to credit the Transition Cost Balancing Account (TCBA) with the estimated
value. The decision encourages the utilities to base such estimates on
realistic assessments of the market value of the assets. The decision
provides that if the estimated market valuation is less than book value for
any individual asset, accelerated amortization of the associated transition
costs will continue until final market valuation of the asset occurs through
sale, appraisal, or other divestiture. If the final value of the assets,
determined through sale, appraisal, or other divestiture, is higher than the
estimate, the excess amount would be used to reduce remaining transition
costs, if any. The utilities are required to file the adjusted entries to
their respective TCBA based on the estimated market values with the CPUC by
May 31, 2000. The filing will become effective after appropriate review by
the CPUC's Energy Division and will be subject to review in the next ATCP. On
May 2, 2000, a proposed decision was issued recommending the establishment of
an accounting mechanism to permit a regulatory asset to be recorded equal to
the amount credited to the TCBA. If an estimate of the market value of the
non-nuclear generating assets is adopted that exceeds the aggregate net book
value of those assets, and if an appropriate accounting mechanism is not
adopted, a charge to earnings would result.
At March 31, 2000, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $0.7 billion, excluding
approximately $0.5 billion of net investment reclassified as regulatory
assets. Any excess of market value over the $0.7 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 the PG&E National Energy Group, 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. As discussed above, it is possible that the
CPUC will require an interim valuation through an estimate of market value of
the assets prior to transfer, sale, or other divestiture, which could also
result in a material charge. While transfer or sale to an affiliated entity
such as the PG&E National Energy Group would result in a material charge to
income, neither PG&E Corporation nor the Utility believes that the sale of any
generation facilities to a third party will have a material impact on its
results of operations.
The Utility's ability to continue recovering its transition costs depends
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, and
(6) the market price of electricity. Given the current evaluation of these
factors, PG&E Corporation believes that the Utility will recover its
transition costs. 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.
Post-Transition Period
- ----------------------
The timing of the end of the rate freeze and corresponding transition
period will, in part, depend on the timing of the valuation of the Utility's
hydroelectric generating assets and the ultimate determined value of such
assets since any excess of market value over the assets' book value would be
used to reduce transition costs. If the value of the Utility's hydroelectric
generation assets is significantly higher than the related book value, the
transition period and the rate freeze could end before December 31, 2001, and
potentially could end during 2000.
In October 1999, the CPUC issued a decision in the Utility's post-
transition period ratemaking proceeding. Among other matters, the CPUC's
decision addresses the mechanisms for ending the current electric rate freeze
and for establishing post-transition period accounting mechanisms and rates.
The decision prohibits the Utility from continuing to price electric
generation from Diablo Canyon based on the incremental cost incentive price
(ICIP) after the transition period has ended. The ICIP, which has been in
place since January 1, 1997, is a performance-based mechanism that establishes
a rate per kWh generated by the facility. The ICIP prices for 1999, 2000, and
2001 are 3.37 cents per kWh, 3.43 cents per kWh, and 3.49 cents per kWh,
respectively. The average price for base load electric energy (the price
received for a constant level of electric generation for all hours of electric
demand) sold at market rates to the California PX for the three-month periods
ended March 31, 2000 and 1999, was 3.6 cents and 2.3 cents per kWh,
respectively. The average price for base load electric energy sold at market
rates to the California PX for the 12 months ending March 31, 2000 was 4.0
cents per kWh. Future market prices may be higher or lower. Under the CPUC's
decision, after the transition period, the Utility must price Diablo Canyon
generation at the prevailing market price for power.
The CPUC decision requires the Utility to provide quarterly forecasts of
when the Utility's rate freeze (i.e., transition period) may end based on
various assumptions regarding energy prices and the market value of the
Utility's remaining generation assets. The Utility is required to notify the
CPUC three months before the earliest forecasted end of its rate freeze and
provide draft tariff language and sample calculations of the rates that would
go into effect when the rate freeze ends. After the Utility completes its
transition cost recovery, it must implement its post-rate-freeze rates.
After the rate freeze and transition periods end, the Utility must refund
to electric customers any over-collected transition costs (plus interest at
the Utility's three-month commercial paper rate) within one year after the end
of the rate freeze. The Utility also will be prohibited from collecting after
the rate freeze certain electric costs incurred during the rate freeze but not
recovered during the rate freeze, including costs that are not classified as
transition costs and are not related to generation assets such as under-
collected accounting balances relating to power purchases. Through the end of
its rate freeze, the Utility will continue to incur certain non-transition
costs and place those costs into balancing and memorandum accounts for future
recovery. There is a risk that the Utility will be unable to collect certain
non-transition costs that, due to lags in the regulatory cost approval
process, have not been approved for recovery nor collected when the rate
freeze ends. The Utility is unable to predict the amount of such potential
unrecoverable costs.
In November 1999, the Utility filed an application for rehearing of the
CPUC's decision. In March 2000, the CPUC denied the Utility's application for
rehearing on the issues of Diablo Canyon ICIP and post-transition period
recovery of non-transition costs. On April 17, 2000, the Utility filed a
petition for review in the California Court of Appeal on the issue of post-
transition period recovery of non-transition costs.
The CPUC also has established the Purchased Electric Commodity Account
(PECA) for the Utility to track energy costs after the rate freeze and
transition period end. The CPUC intends to explore other ratemaking issues,
including whether dollar-for-dollar recovery of energy costs is appropriate,
in the second phase of the post-transition period electric ratemaking
proceeding. There are three primary options for the future regulatory
framework for utility electric energy procurement cost recovery after the rate
freeze: (1) a CPUC-defined procurement practice, that if followed by the
Utility, would pass through costs without the need for reasonableness reviews,
(2) a pass-through of costs subject to after-the-fact reasonableness reviews,
or (3) a procurement incentive mechanism with rewards and penalties determined
based on the Utility's energy purchasing performance compared to a benchmark.
The Utility proposed adoption of either a defined procurement practice or a
procurement incentive mechanism, neither of which would involve reasonableness
reviews. On March 17, 2000, the CPUC issued a proposed decision that states
that after the rate freeze, there will be two electric rate proceedings to
address electric energy procurement practices and rates. The Revenue
Adjustment Proceeding (RAP) will be a forecast of costs, and the ATCP will
include a review of procurement costs to the extent costs above the wholesale
PX rate are included in the PECA. The volatility of earnings and risk
exposure of the Utility related to post-transition period purchases of
electricity is dependent on which of these options, or some other approach, is
adopted.
Further, pursuant to the 1997 CPUC decision establishing the ICIP, the
Utility is required to begin sharing 50 percent of the net benefits of
operating Diablo Canyon with ratepayers at the end of the transition period.
The Utility is required to file an application by July 2000 with its proposal
for the methods to be used in the valuation of the benefits associated with
the operation of Diablo Canyon, and the mechanism to be used to share these
benefits with ratepayers. The Utility and PG&E Corporation are unable to
predict what type of valuation and sharing mechanism will be adopted and what
the ultimate financial impact of the sharing mechanism will have on results of
operation or financial position.
The ultimate financial impact of the provisions of the post-transition
period issues discussed above will depend on the date the Utility's transition
cost recovery is completed and the rate freeze ends, future costs including
Diablo Canyon operating costs, future market prices for electricity, the
method adopted by the CPUC for sharing net benefits of operating Diablo Canyon
with ratepayers, the amount of any electric non-transition costs that have
been incurred but not recovered as of the end of the rate freeze, the timing
of various regulatory proceedings in which the Utility seeks approval for rate
recovery of various costs incurred during the rate freeze, and other variables
that PG&E Corporation and the Utility are unable to predict.
After the transition period, the Utility's future earnings from its
electric distribution will be subject to volatility due to sales fluctuations.
Distributed Generation and Electric Distribution Competition
- ------------------------------------------------------------
In October 1999, the CPUC issued a decision outlining how the CPUC, in
cooperation with other regulatory agencies and the California Legislature,
plans to address the issues surrounding distributed generation, electric
distribution competition, and the role of the utility distribution companies
(such as Pacific Gas and Electric Company) in the competitive retail electric
market. Distributed generation enables siting of electric generation
technologies in close proximity to the electric demand (referred to as
"load"). The CPUC decision opened a new rulemaking proceeding to examine
various issues concerning distributed generation, including interconnection
issues, who can own and operate distributed generation, environmental impacts,
the role of utility distribution companies, and the rate design and cost
allocation issues associated with the deployment of distributed generation
facilities. With respect to electric distribution competition, the CPUC
directed its staff to deliver a report by June 2, 2000, on the different
policy options that the CPUC, in cooperation with the California Legislature,
can pursue. Following the issuance of the report, the CPUC expects to open
one or more new proceedings to address electric distribution competition and
competition in the retail electric market.
PG&E NATIONAL ENERGY GROUP
The PG&E National Energy Group has been formed to pursue opportunities
created by the gradual restructuring of the energy industry across the nation.
The PG&E National Energy Group integrates our national power generation, gas
transmission, and energy trading and services businesses. The PG&E National
Energy Group contemplates increasing PG&E Corporation's national market
presence through a balanced program of acquisition and development of energy
assets and businesses, while at the same time undertaking ongoing portfolio
management of its assets and businesses. The PG&E National Energy Group's
ability to anticipate and capture profitable business opportunities created by
restructuring will have a significant impact on PG&E Corporation's future
operating results.
Independent Power Generation
- ----------------------------
Through PG&E Gen and its affiliates, we participate in the development,
construction, operation, ownership, and management of non-utility electric
generating facilities that compete in the United States power generation
market. 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 the 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.
As part of the New England electric industry restructuring, the local
utility companies were required to offer Standard Offer Service (SOS) to their
retail 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
31, 2004, in Massachusetts, and through December 31, 2009, in Rhode Island.
However, if customers choose an alternate supplier, they are precluded from
going back to the SOS.
In connection with the purchase of the generation assets, USGenNE entered
into wholesale agreements with certain of the retail companies of NEES to
supply at specified prices the electric capacity and energy requirements
necessary for their retail companies to meet their SOS obligations. These
companies are responsible for passing on to us the revenues generated from the
SOS. USGenNE currently is indirectly serving a large portion of the SOS
electric capacity and energy requirements for these companies, except in New
Hampshire. For the three months ended March 31, 2000, the SOS price paid to
generators was $0.038 per kWh for generation. On March 1, 1999, Constellation
Power Source, Inc. (Constellation) won the New Hampshire component of the SOS
through a competitive bidding solicitation. On January 7, 2000, USGenNE paid
approximately $15 million to a third party for this third party's assumption
of 10 percent of the Massachusetts Electric Company/Nantucket Electric Company
SOS and 40 percent of the Narragansett SOS.
Like other utilities, New England utilities previously entered into
agreements with unregulated companies (e.g., qualifying facilities under the
Public Utility Regulatory Policies Act of 1978 (PURPA)) 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. At March 31, 2000, these agreements provided for an
aggregate 655 MW of capacity. However, NEES will make support payments to us
toward the cost of these agreements. The support payments by NEES total $0.9
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 servicing SOS customers. To
the extent that customers eligible to receive SOS choose alternate suppliers,
or as these obligations are sold to other parties, this percentage will
decrease. As customers choose alternate suppliers, or the SOS obligations are
sold, a greater proportion of the output of the acquired operating capacity
will be subject to market prices.
Gas Transmission Operations
- ---------------------------
PG&E Corporation participates in the "midstream" portion of the gas
business through PG&E GT NW. PG&E GT NW owns and operates gas transmission
pipelines and associated facilities which extend over 612 miles from the
Canada-U.S. border to the Oregon-California border. PG&E GT NW provides firm
and interruptible transportation services to third party shippers on an open-
access basis. Its customers are principally retail gas distribution
utilities, electric utilities that use natural gas to generate electricity,
natural gas marketing companies, natural gas producers, and industrial
consumers.
On January 27, 2000, the PG&E National Energy Group signed a definitive
agreement with El Paso Field Services Company (El Paso) providing for the sale
to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of PG&E
Gas Transmission, Texas Corporation and PG&E Gas Transmission Teco, Inc.
(collectively, PG&E GT-Texas). The consideration to be received by the PG&E
National Energy Group includes $279 million in cash subject to a working
capital adjustment, the assumption by El Paso of debt having a book value of
$624 million, and other liabilities associated with PG&E GT-Texas.
In 1999, PG&E Corporation recognized a charge against earnings of $890
million after tax, or $2.42 per share, to reflect PG&E GT-Texas' assets at
their fair market value. The composition of the pre-tax charge is as follows:
(1) an $819 million write-down of net property, plant, and equipment, (2) the
elimination of the unamortized portion of goodwill, in the amount of $446
million, and (3) an accrual of $10 million representing selling costs.
Proceeds from the sale will be used to retire short-term debt associated
with PG&E GT-Texas' operations and for other corporate purposes. Closing of
the sale, which is expected in the first half of 2000, is subject to approval
under the Hart-Scott-Rodino Act.
Energy Trading
- --------------
Through PG&E ET, we purchase bulk volumes of power and natural gas from
PG&E Corporation affiliates and the wholesale market. We then schedule,
transport, and resell these commodities, either directly to third parties or
to other PG&E Corporation affiliates. PG&E ET also provides risk management
services to PG&E Corporation's other businesses (except the Utility) and to
wholesale customers. (See "Price Risk Management Activities" below; and Note
3 of the Notes to Condensed Consolidated Financial Statements.)
Energy Services
- ---------------
In December 1999, PG&E Corporation's Board of Directors approved a plan to
dispose of PG&E ES, its wholly owned subsidiary, through a sale. The intended
disposal has been accounted for as a discontinued operation. In connection
with this transaction, PG&E Corporation's investment in PG&E ES was written
down to its estimated net realizable value in 1999. In addition, in 1999,
PG&E Corporation provided a reserve for anticipated losses through the date of
sale. The total provision for discontinued operations was $58 million, net of
income taxes of $36 million. During the three month period ended March 31,
2000 $14.7 million was charged against this reserve. On April 12, 2000, the
PG&E National Energy Group signed an agreement to sell specified assets,
liabilities, and contracts of PG&E Energy Services Corporation. The
consideration to be received by the PG&E National Energy Group is $20 million,
plus net working capital of approximately $65 million, for a total of $85
million. The transaction is expected to close by June 2000. The remaining
components of PG&E Energy Services Corporation, mainly the Value Added
Services business and various other assets, will continue to be offered for
sale. The PG&E National Energy Group expects to complete this disposition
prior to year-end 2000. The disposition of PG&E ES has been reflected in the
financial statements as a discontinued operation. The PG&E ES business segment
generated net losses of $8 million (or $0.02 per share) for the three-month
period ended March 31, 1999.
REGULATORY MATTERS
A significant portion of PG&E Corporation's operations are regulated by
federal and state regulatory commissions. These commissions oversee service
levels and, in certain cases, PG&E Corporation's revenues and pricing for its
regulated services. The Utility is the only subsidiary with significant
regulatory proceedings at this time. Any change in authorized electric
revenues resulting from any of the electric proceedings discussed below would
not impact the Utility's customer electric rates because these rates are
frozen throughout the transition period. However, any change would affect the
amount of revenues available for the recovery of transition costs. Any change
in authorized gas revenues resulting from gas proceedings would result in a
change in the Utility's customer gas rates.
The 1999 General Rate Case (GRC)
- --------------------------------
The CPUC's final decision issued in February 2000 in the Utility's 1999 GRC
application increased annual electric distribution revenues by $163 million
and annual gas distribution revenues by $93 million, as compared to revenues
authorized for 1998. Although the increase in electric and gas distribution
revenues was retroactive to January 1, 1999, prior quarters were not restated.
Instead, the entire increase was reflected in the fourth quarter of 1999. Had
the Utility restated prior quarters, 1999 first quarter net earnings would
have been $40 million higher than reported.
The Utility's GRC application also contained a proposal for an Attrition
Rate Adjustment (ARA) to adjust revenues in 2000 and 2001. The ARA would
increase authorized revenues to offset cost increases during these periods.
The final decision denies the Utility's request for an ARA to adjust revenues
in 2000, but adopts an ARA for 2001. The final decision orders that the CPUC
oversee an audit of the Utility's 1999 distribution capital spending, and that
the 2001 ARA be subject to modification to take into account the results of
the audit. The 2001 ARA will also be subject to modification to recognize
amounts recorded in a new balancing account that the final decision requires
be established for vegetation management expenses.
In March 2000, two intervenors filed applications for rehearing of the GRC
decision, alleging that the CPUC committed legal errors by approving funding
in certain areas that were not adequately supported by record evidence. In
April 2000, the Utility filed its response to these applications for
rehearing, defending the GRC decision against the allegations of error. A
CPUC decision on the applications for rehearing is expected in the second
quarter of 2000.
Also in the 1999 GRC final decision, the CPUC ordered the Utility to file a
2002 GRC. The Utility currently intends to file a Notice of Intent with the
CPUC in the third quarter of 2000. This date may be extended, depending upon
the outcome of an April 27, 2000 ruling from two CPUC Commissioners,
requesting comments on whether the CPUC should delay the Utility's 2002 GRC by
six months. In seeking these comments, the Commissioners stated that if the
2002 GRC were delayed, rates could still become effective on January 1, 2002,
although the CPUC decision may not be rendered until mid-2002.
The Year 2000 Cost of Capital Proceeding
- ----------------------------------------
In April 2000, the Utility reached a settlement with the ORA and several
intervenor groups and will make a joint recommendation to the CPUC. The joint
recommendation specifies a return on common equity (ROE) of 11.22 percent on
electric and gas distribution operations, retroactive to February 17, 2000.
The Utility's current authorized ROE is 10.6 percent. The joint
recommendation also recommends no changes to the currently authorized Utility
capital structure of 46.2 percent long-term debt, 5.8 percent preferred stock,
and 48.0 percent common equity.
If adopted by the CPUC, the recommendation would result in an authorized
9.12 percent overall return on Utility electric and gas distribution rate
base. This would increase the Utility's 2000 electric and gas revenues by
approximately $37 million and $12 million, respectively.
A final CPUC decision on the parties' recommendation is expected in the
second quarter of 2000.
The Year 2001 Cost of Capital Proceeding
- ----------------------------------------
On May 8, 2000, the Utility filed an application with the CPUC to establish
its authorized rate of return (ROE) for electric and gas distribution
operations for 2001. The application requests a ROE of 12.4 percent, and an
overall rate of return (ROR) of 9.75 percent. The Utility's proposal for test
year 2001 ROE for its electric distribution and gas distribution lines of
business is 118 basis points higher than the 2000 settlement ROE of 11.22
percent currently pending before the CPUC. If granted, the requested ROE
would increase electric distribution revenues by approximately $72 million and
gas distribution revenues by approximately $23 million, as compared with the
2000 settlement ROE of 11.22 percent currently pending before the CPUC. The
application also requests authority to implement an Annual Cost of Capital
Adjustment Mechanism for 2002 through 2006 that would replace the annual cost
of capital proceedings. The proposed adjustment mechanism would modify the
Utility's cost of capital based on changes in an interest rate index. The
Utility also proposes to maintain its currently authorized capital structure
of 46.2 percent long-term debt, 5.8 percent preferred stock, and 48.0 percent
common equity.
FERC Transmission Rate Cases
- ----------------------------
Since April 1998, electric transmission revenues have been authorized by
the FERC, including various rates to recover transmission costs from the
Utility's former bundled retail transmission customers. The FERC has not yet
acted upon a settlement filed by the Utility that, if approved, would allow
the Utility to recover $345 million in electric transmission rates for the 14-
month period of April 1, 1998 through May 31, 1999. During this period,
somewhat higher rates have been collected, subject to refund. However, in
April 2000, the FERC approved a settlement that permits the Utility to recover
$264 million in electric transmission rates for the 10-month period of May 31,
1999 to March 31, 2000. Further, in October 1999, the FERC accepted, subject
to refund, the Utility's proposal to collect $370 million annually in electric
transmission rates beginning on April 1, 2000. The Utility does not expect a
material impact on its financial position or results of operations resulting
from these matters.
Catastrophic Event Memorandum Account Proceeding
- ------------------------------------------------
As previously disclosed, in September 1999, the Utility entered into a
settlement agreement with the ORA, and other parties, providing for an
increase in electric and gas distribution revenue requirements to compensate
the Utility for service restoration costs recorded in the Catastrophic Events
Memorandum Account. In April 2000, the CPUC approved the proposed settlement
and collection over the remainder of the year.
The CPUC's Gas Strategy Investigation, Phase 2
- ----------------------------------------------
In January 1998, the CPUC opened a rulemaking proceeding to explore changes
in the natural gas industry in California. In July 1999, the CPUC issued a
decision identifying options for restructuring the natural gas industry. In
the decision, the CPUC reaffirmed the basic structure of the Gas Accord. The
CPUC further stated that it seeks to explore a market structure that maintains
the utilities' traditional role of providing fully integrated default service
while removing obstacles to competitive unbundled services. The CPUC opened a
new investigative proceeding to explore in more detail the anticipated costs
and benefits associated with the different market structure options it has
identified. In January 2000, the Utility and a broad-based coalition of
shippers, consumer groups, marketers, and others filed a settlement with the
CPUC which would reaffirm the basic structure of the Gas Accord and continue
the Gas Accord through its original term of December 2002.
RESULTS OF OPERATIONS
The table below shows for the quarter ended March 31, 2000 and 1999,
certain items from our Statement of Consolidated Income detailed by Utility
and PG&E 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 from the quarter for 2000.
Utility PG&E National Energy Group
------- ---------------------------------------------
PG&E GT Elimi-
---------------- nations &
PG&EGen NW Texas PG&E ET Other (1) Total
------- ------- ------- ------- ------- --------- -------
(in millions)
March 31, 2000
- --------------
Operating revenues $ 2,218 $ 312 $ 57 $ 225 $ 2,557 $ (361) $ 5,008
Operating expenses 1,648 255 25 210 2,544 (350) 4,332
------- ------- ------- ------- ------- ------ -------
Operating income 570 57 32 15 13 (11) 676
Other income, net 15
Interest expense 183
Income taxes 228
Income from continuing
operations 280
Net income $ 280
EBITDA (2) $ 864 $ 78 $ 42 $ 12 $ 17 $ (10) $ 1,003
March 31, 1999
- --------------
Operating revenues $ 2,085 $ 289 $ 58 $ 357 $ 2,631 $ (294) $ 5,126
Operating expenses 1,663 243 27 383 2,636 (287) 4,665
------- ------- ------- ------- ------- ------ -------
Operating income 422 46 31 (26) (5) (7) 461
Other income, net 21
Interest expense 201
Income taxes 114
Income from continuing
operations 167
Net income $ 171
EBITDA (2) $ 795 $ 70 $ 41 $ (7) $ (3) $ (7) $ 889
<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.
Overall Results
- ---------------
PG&E Corporation's net income for the first quarter of 2000 increased 63.7
percent to $280 million from $171 million in the prior year's first quarter.
Of the $109 million increase, the PG&E National Energy Group accounted for $28
million of the increase and the Utility's first quarter net income available
for common stock increased to $228 million from $147 million in the prior
year.
The strong increase in performance is attributable to the following
factors:
- In the first quarter of 2000, the Utility received the final order on its
general rate case. Although the increase in revenue requirements was
retroactive to January 1, 1999, the prior quarters were not restated and the
entire increase was reflected in the fourth quarter of 1999. The outcome of
the rate order increased first quarter Utility net earnings approximately $40
million ($0.11 per share) compared to the first quarter of 1999.
- In the first quarter of 1999, Diablo Canyon completed a scheduled refueling
outage for one of its plants. There was no such outage during the first
quarter of 2000, resulting in an approximate $36 million ($0.10 per share)
increase in 2000 first quarter net earnings.
- PG&E ET's first quarter 2000 net income increased $14 million over 1999
first quarter results due to across the board improvements in gas and power
trading, in asset management and structured transactions. This increase was
net of a $4 million after-tax ($.01 per share) charge for severance costs
associated with the restructuring of the PG&E National Energy Group.
- At the end of 1999, PG&E Corporation announced its plans to dispose of PG&E
GT-Texas and PG&E ES in separate transactions. The PG&E GT-Texas assets were
written down to estimated fair value and the PG&E ES assets were reflected as
discontinued operations. Net losses associated with those business segments
amounted to $32 million ($0.08 per share) in the first quarter of 1999.
- Effective the first quarter of 1999, PG&E Corporation changed its method of
accounting for major maintenance and overhauls at PG&E National Energy Group.
Beginning January 1, 1999, the cost of major maintenance and overhauls,
principally at the PG&E Gen business segment, have been accounted for as
incurred. The change resulted in PG&E Corporation recording income of $12
million after-tax ($0.03 per share), reflecting the cumulative effect of the
change in accounting principle.
EBITDA has increased 12.8 percent to $1,003 million from $889 million in
the prior year's first quarter as a result of the increased operating
performance of the Utility and PG&E ET described above.
Operating Revenues
- ------------------
Utility operating revenues increased $133 million in the first quarter of
2000 to $2.2 billion over first quarter 1999 revenues of $2.1 billion. The
increase is a result of higher sales to residential customers reflecting an
increase in the number of customers and to industrial customers due to an
increase in the average customer usage. This increase was partially offset by
a decrease in natural gas sales because of milder winter weather.
PG&E National Energy Group operating revenues declined $251 million in the
first quarter of 2000 compared to the first quarter of 1999. The decline
reflects a significant decline in trading volume in natural gas and natural
gas liquids. PG&E National Energy Group has focused its trading efforts on
asset management, structured transactions and higher margin trades resulting
in a decrease in trading volume and an increase in gross profit margin.
Operating Expenses
- ------------------
Utility operating expenses decreased $15 million in the first quarter of
2000 to $1.6 billion from first quarter 1999. The decrease in operating
expenses is a result of less depreciation expense because of the sale of 4,289
MW of fossil-fueled and geothermal generation facilities in the second quarter
of 1999. Also contributing to the decrease in operating expenses was a
decline in operating and maintenance expense reflecting the impact in 1999 of
the Diablo Canyon scheduled refueling outage with no such scheduled outage in
the first quarter of 2000. These decreases were partially offset by an
increase in the cost of electric energy, which experienced both price and
volume increases in the first quarter of 2000 over the first quarter of 1999.
Operating expenses at PG&E National Energy Group declined $318 million in
the first quarter of 2000 from $3 billion in the first quarter of 1999. The
decrease results from the reduced trading volumes discussed above, cost
control efforts throughout PG&E National Energy Group and reduced depreciation
and amortization expense at PG&E GT-Texas reflective of the write-down to fair
value of the PG&E GT-Texas assets held for sale.
Income Taxes
- ------------
The effective tax rate for the Corporation has increased to 44.9 percent in
the current quarter from 40.6 percent in the prior year's first quarter as a
result of: (1) electric industry restructuring which has resulted in the
reversal of temporary tax differences at the Utility whose tax benefits were
originally flowed through to customers causing an increase in income tax
expense independent of pre-tax income and, (2) higher state taxes.
Dividends
- ---------
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 $1,062
million and $1,025 million in the quarters ended March 31, 2000 and 1999,
respectively. Net cash provided by the Utility's operating activities totaled
$688 million and $1,092 million in the quarters ended March 31, 2000 and 1999,
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 quarter ended March 31, 2000, we issued $10 million of common
stock, primarily through the Dividend Reinvestment Plan and the stock option
plan component of the Long-Term Incentive Program. During the quarter ended
March 31, 2000, we paid dividends on our common stock of $108 million.
In October 1999, the Board of Directors of PG&E Corporation authorized an
additional $500 million for the purpose of repurchasing shares of the
Corporation's common stock on the open market. This authorization supplements
the approximately $40 million remaining from the amount previously authorized
by the Board of Directors on December 17, 1997. The authorization for share
repurchase extends through September 30, 2001. As of March 31, 2000, through
our wholly owned subsidiary, we repurchased 7.2 million shares, at a cost of
$159 million under this authorization. Any open market purchases will be made
by the wholly owned subsidiary of PG&E Corporation.
During the three months ended March 31, 2000, the PG&E National Energy Group
retired $99 million of long-term debt.
We maintain a number of credit facilities to support commercial paper
programs, letters of credit, and other short-term liquidity requirements. PG&E
Corporation maintains two $500 million revolving credit facilities, one of
which expires in November 2000 and the other in 2002. These credit facilities
are used to support the commercial paper program and other liquidity needs.
The facility expiring in 2000 may be extended annually for additional one-year
periods upon agreement with the lending institutions. There was $100 million
of commercial paper outstanding at March 31, 2000. PG&E Corporation introduced
a $200 million Extendible Commercial Note (ECN) program during the third
quarter of 1999. The ECN program supplements our short-term borrowing
capability. There was $98 million of extendible commercial notes outstanding
at March 31, 2000, which are not supported by the credit facilities.
PG&E Gen maintains two $550 million revolving credit facilities. One
facility expires in August 2000 and the other expires in 2003. The total
amount outstanding at March 31, 2000, backed by the facilities, was $903
million in commercial paper. Of these loans, $550 million is classified as
noncurrent in the Consolidated Balance Sheet of PG&E Corporation.
In 1998, USGenNE, a subsidiary of PG&E Gen, established a $100 million
revolving credit facility that expires in 2003. As of March 31, 2000, there is
no outstanding balance on this facility.
PG&E GT NW maintains a $100 million revolving credit facility that expires
in 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 that expires in 2000, but can be extended for successive 364-day
periods. At March 31, 2000, PG&E GT NW had an outstanding commercial paper
balance of $64 million, which is classified as noncurrent in the Consolidated
Balance Sheet of PG&E Corporation.
PG&E GTT maintains four separate credit facilities that total $250 million
and are guaranteed by PG&E Corporation. At March 31, 2000, PG&E GTT had $192
million of outstanding short-term bank borrowings related to these 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.
Utility:
During the three months ended March 31, 2000, the Utility paid dividends on
its common stock of $122 million. In April 2000, the Utility repurchased from
PG&E Corporation 11.9 million shares of its common stock at a cost of $275
million.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during the three months ended March 31, 2000, totaled $102 million.
Of this amount, $73 million related to the Utility's rate reduction bonds
maturing, and $27 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 March 31, 2000, backed by this facility, was $209 million
in commercial paper.
Cash Flows from Investing Activities
- ------------------------------------
Utility:
The primary uses of cash for investing activities are additions to property,
plant, and equipment, unregulated investments in partnerships, and
acquisitions.
The Utility's estimated capital spending for 2000 is approximately $1.3
billion, excluding capital expenditures for divested fossil and geothermal
power plants. The Utility's capital expenditures for the three months ended
March 31, 2000, was $265 million.
PG&E National Energy Group:
PG&E Gen is associated with the construction of three natural gas-fueled
combined-cycle power plants. These power plants, referred to as "merchant
power plants," will sell power as a commodity in the competitive marketplace.
The electricity generated by these plants will be sold on a wholesale basis to
local utilities and power marketers, including PG&E ET, which, in turn, will
sell it to industrial, commercial, and other electricity customers.
Millennium Power, a 360-MW power plant located in Massachusetts, is
scheduled to begin commercial service in the first quarter of 2001. Lake Road
Generating Plant (Lake Road), an approximately 790-MW power plant located in
Connecticut, is scheduled to begin commercial service in 2001. La Paloma
Generating Plant (La Paloma), an approximately 1,050-MW power plant, is located
in California, and is scheduled to begin commercial service in 2001. Lake Road
and La Paloma are being financed through synthetic leases with a third party
owner. PG&E Gen will operate the plants under operating leases. The estimated
cost to construct these plants is approximately $1.4 billion.
PG&E Gen broke ground for the Madison Wind Power Project in New York in
April 2000. This 11.5 MW project will be the largest wind generating facility
in the Eastern United States and is expected to be operational in September
2000. The estimated cost to construct this plant is $16 million.
USGenNE has proposed an emission reduction plan which may include a $400
million modernization of its 760-MW coal-fired power plant in Salem,
Massachusetts. The proposed modernization will use advanced technologies for
emissions removal, with construction beginning in 2002 and ending by January
2004.
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.
At March 31, 2000, the Utility has accrued $275 million ($303 million on an
undiscounted basis) for clean-up costs at identified sites. If other
responsible parties fail to pay or expected outcomes change, then these costs
may be as much as $501 million. Of the $275 million, the Utility has recovered
$148 million through rates, including $34 million through depreciation and
expects to recover another $99 million in future rates. Additionally, the
Utility mitigates its cost by seeking recovery from insurance carriers and
other third parties. (See Note 6 of Notes to Condensed Consolidated Financial
Statements.)
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 estimates the upper limit of the range
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 clean-up costs at additional sites or expected outcomes
change.
In addition to the potential $400 million modernization of the coal-fired
power plant located on Salem Harbor in Salem, Massachusetts, USGenNE also is
studying various modernization alternatives for its 1,586 MW coal-fired
Brayton Point power plant in Somerset, Massachusetts. On April 18, 2000 the
Conservation Law Foundation (CLF) served various PG&E Gen affiliates,
including USGenNE, a notice of its intent to file suit under the citizen suit
provision of the Resource Conservation Recovery Act. CLF stated in such
notice that it plans in its suit to allege that the PG&E Gen affiliates,
generator of fossil fuel combustion wastes, has and is contributing to the
past and present handling, storage, treatment and disposal of such wastes at
the Salem Harbor and Brayton Point power plants which may present an imminent
and substantial endangerment to health or the environment. It further stated
it will allege that PG&E Gen's management practices in connection with such
wastes has resulted in severe groundwater contamination at both facilities.
CLF has stated that it intends to seek an order requiring all necessary
measures be taken to halt what it characterizes as the endangerment of health
and environment. At this preliminary stage, we are unable to determine
whether the ultimate outcome of this matter would have a material adverse
effect on our results of operations or financial condition.
RISK MANAGEMENT ACTIVITIES
We have established a risk management policy that allows derivatives to be
used for both hedging and non-hedging purposes (a derivative is a contract
whose value is dependent on or derived from the value of some underlying
asset). We use derivatives for hedging purposes primarily to offset underlying
commodity price risks. We also participate in markets using derivatives to
gather market intelligence, create liquidity, and maintain a market presence.
Such derivatives include forward contracts, futures, swaps, and options. Net
open positions often exist or are established due to PG&E Corporation's
assessment of its response to changing market conditions. To the extent that
PG&E Corporation has an open position, it is exposed to the risk that
fluctuating market prices may adversely impact its financial results. Our risk
management policy and the trading and risk management policies of our
subsidiaries prohibit the use of derivatives whose payment formula includes a
multiple of some underlying asset.
We prepare a daily assessment of our portfolio market risk exposure using
value-at-risk and other methodologies that simulate future price movements in
the energy markets to estimate the size and probability of future potential
losses. The quantification of market risk using value-at-risk provides a
consistent measure of risk across diverse energy markets and products. The use
of this methodology requires a number of important assumptions, including the
selection of a confidence level for losses, volatility of prices, market
liquidity, and a holding period. PG&E Corporation's daily value-at-risk for
commodity price sensitive derivative instruments as of March 31, 2000, was $1.6
million for trading activities and $0.3 million for non-trading activities.
Value-at-risk has several limitations as a measure of portfolio risk,
including, but not limited to, underestimation of the risk of a portfolio with
significant options exposure, inadequate indication of the exposure of a
portfolio to extreme price movements, and the inability to address the risk
resulting from intra-day trading activities.
In June 1999, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 137, "Accounting for
Derivative Instruments and Hedging Activities-Deferral of the Effective Date of
FASB Statement No. 133," which delayed the implementation of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities," by one year to
require adoption in years beginning after June 15, 2000. The Statement permits
early adoption as of the beginning of any fiscal quarter.
PG&E Corporation expects to adopt SFAS No. 133 no later than January 1,
2001. The Statement will require us to recognize all derivatives, as defined in
the Statement, on the balance sheet at fair value. Derivatives, or any portion
thereof, that are not effective hedges must be adjusted to fair value through
income. If derivatives are effective hedges, depending on the nature of the
hedges, changes in the fair value of derivatives either will be offset against
the change in fair value of the hedged assets, liabilities, or firm commitments
through earnings, or will be recognized in other comprehensive income until the
hedged items are recognized in earnings. We currently are evaluating what the
effect of SFAS No. 133 will be on the earnings and financial position of PG&E
Corporation. However, we already use the mark-to-market method of accounting
for our commodity non-hedging and risk management activities.
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 5 of Notes to
Condensed Consolidated Financial Statements for further discussion of
significant pending legal matters.)
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
-------------------------------------------------------------------
PG&E Corporation's and Pacific Gas and Electric Company's primary market risk
results from changes in energy prices and interest rates. We engage in price
risk management activities for both non-hedging and hedging purposes.
Additionally, we may engage in hedging activities using futures, options, and
swaps to hedge the impact of market fluctuations on energy commodity prices,
interest rates, and foreign currencies. (See Risk Management Activities,
above.)
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
-----------------
Moss Landing Power Plant
In December 1999, the Utility was notified by the purchaser of its former
Moss Landing power plant that it had identified a cleaning procedure used
at the plant that released heated water and organic debris from the intake,
and that this procedure is not specified in the plant's National Pollutant
Discharge Elimination System (NPDES) permit issued by the Central Coast
Regional Water Quality Control Board (Central Coast Board). The purchaser
notified the Central Coast Board of its findings and the Central Coast
Board requested additional information from the purchaser. The Utility
initiated an investigation of these activities during the time it owned the
plant. The Utility notified the Central Coast Board that it had undertaken
an investigation and that it would present the results to the Central Coast
Board when the investigation was completed. On March 15, 2000, the Central
Coast Board sent a letter to the Utility requesting specific information
regarding the "backflush" procedure used at Moss Landing. The Utility
completed its investigation and provided the requested information to the
Central Coast Board on April 7, 2000. Until the results of the Utility's
investigation are discussed with the Central Coast Board, it is not
possible to determine whether the Utility will suffer a loss in connection
with this matter or to provide a more detailed estimate of such liability.
Item 4. Submission of Matters to a Vote of Security Holders
---------------------------------------------------
PG&E Corporation:
On April 19, 2000, PG&E Corporation held its annual meeting of
shareholders. At that meeting, the shareholders voted as indicated below
on the following matters:
1. Election of the following directors to serve until the next annual
meeting of shareholders or until their successors are elected and
qualified:
For Withheld
---------- ----------
Richard A. Clarke 252,017,302 9,890,523
Harry M. Conger 252,942,092 8,965,733
David A. Coulter 252,110,956 9,796,869
C. Lee Cox 253,040,357 8,867,468
William S. Davila 253,036,334 8,871,491
Robert D. Glynn, Jr. 252,909,447 8,998,378
David M. Lawrence, MD 252,705,855 9,201,970
Mary S. Metz 252,995,318 8,912,507
Carl E. Reichardt 252,790,649 9,117,176
John C. Sawhill 253,084,819 8,823,006
Barry Lawson Williams 252,723,645 9,184,180
2. Ratification of the appointment of Deloitte & Touche LLP as
independent public accountants for 2000:
For: 256,379,276
Against: 2,506,940
Abstain: 3,021,609
The proposal was approved by a majority of the shares present and voting
(including abstentions) which shares voting affirmatively also constituted
a majority of the required quorum.
3. Management proposal regarding proposed amendments to PG&E
Corporation's Articles of Incorporation to implement the elimination
of a supermajority vote provision.
For: 206,193,826
Against: 10,349,714
Abstain: 5,261,226
Broker non-vote:(1) 40,103,059
The proposal was approved by a majority of the outstanding shares.
4. Management proposal regarding proposed amendment to PG&E Corporation's
Articles of Incorporation to decrease the authorized minimum and
maximum number of directors:
For: 250,306,476
Against: 6,974,397
Abstain: 4,626,543
Broker non-vote:(1) 409
The proposal was approved by a majority of the outstanding shares.
5. Consideration of a shareholder proposal to appoint independent
directors to key Board committees:
For: 95,827,965
Against: 115,539,858
Abstain: 10,431,336
Broker non-votes:(1) 40,108,666
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
6. Consideration of a shareholder proposal regarding confidential
shareholder voting:
For: 108,057,613
Against: 106,010,434
Abstain: 7,730,522
Broker non-votes:(1) 40,109,256
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
- ---------------
(1) A non-vote occurs when a broker or other nominee holding shares for a
beneficial owner indicates a vote on one or more proposals, but does not
indicate a vote on other proposals because the broker or other nominee does
not have discretionary voting power as to such proposals and has not received
voting instructions from the beneficial owner as to such proposals.
7. Consideration of a shareholder proposal regarding the treatment of
abstentions:
For: 30,290,100
Against: 180,368,498
Abstain: 11,173,674
Broker non-votes:(1) 40,075,553
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
8. Consideration of a shareholder proposal regarding cumulative voting:
For: 72,824,979
Against: 135,858,343
Abstain: 13,115,837
Broker non-votes:(1) 40,108,666
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
9. Consideration of a shareholder proposal regarding compensation of
directors in stock:
For: 28,219,661
Against: 183,248,630
Abstain: 10,330,868
Broker non-votes:(1) 40,108,666
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
10. Consideration of a proposal regarding severance benefits received
during mergers or acquisitions:
For: 36,508,116
Against: 176,996,783
Abstain: 8,294,260
Broker non-votes:(1) 40,108,666
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the
shares voting and present (including abstentions but excluding broker non-
votes) with respect to the proposal.
- ---------------
(1) A non-vote occurs when a broker or other nominee holding shares for a
beneficial owner indicates a vote on one or more proposals, but does not
indicate a vote on other proposals because the broker or other nominee does
not have discretionary voting power as to such proposals and has not received
voting instructions from the beneficial owner as to such proposals.
Pacific Gas and Electric Company:
On April 19, 2000, Pacific Gas and Electric Company held its annual meeting
of shareholders. Shares of capital stock of Pacific Gas and Electric
Company consist of shares of common stock and shares of first preferred
stock. As PG&E Corporation and a subsidiary own all of the outstanding
shares of common stock, they hold approximately 95% of the combined voting
power of the outstanding capital stock of Pacific Gas and Electric Company.
PG&E Corporation and the subsidiary voted all of their respective shares of
common stock for the nominees named in the joint proxy statement and for
the ratification of the appointment of Deloitte & Touche LLP as independent
public accountants for 2000. The balance of the votes shown below were cast
by holders of shares of first preferred stock. At the annual meeting, the
shareholders voted as indicated below on the following matters:
1. Election of the following directors to serve until the next annual
meeting of shareholders or until their successors are elected and
qualified:
For Withheld
----------- -----------
Richard A. Clarke 338,548,826 187,097
Harry M. Conger 338,566,995 168,928
David A. Coulter 338,547,768 188,155
C. Lee Cox 338,570,513 165,410
William S. Davila 338,567,649 168,274
Robert D. Glynn, Jr. 338,559,318 176,605
David M. Lawrence, MD 338,556,908 179,015
Mary S. Metz 338,563,724 172,199
Carl E. Reichardt 338,551,976 183,947
John C. Sawhill 338,569,718 166,205
Gordon R. Smith 338,561,480 174,443
Barry Lawson Williams 338,566,195 169,728
2. Ratification of the appointment of Deloitte & Touche LLP as
independent public accountants for 2000:
For: 338,539,587
Against: 47,602
Abstain: 148,734
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 three months ended March 31, 2000, was 3.89. Pacific Gas and
Electric Company's earnings to combined fixed charges and preferred
stock dividends ratio for the three months ended March 31, 2000, was
3.67. The statement of the foregoing ratios, together with the
statements of the computation of the foregoing ratios filed as
Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of
incorporating such information and exhibits into Registration Statement
Nos. 33-62488, 33-64136, 33-50707, and 33-61959, relating to Pacific Gas
and Electric Company's various classes of debt and first preferred stock
outstanding.
Item 6. Exhibits and Reports on Form 8-K
--------------------------------
(a) Exhibits:
Exhibit 3.1 Restated Articles of Incorporation of PG&E Corporation,
dated as of May 5, 2000
Exhibit 3.2 Bylaws of PG&E Corporation, dated as of May 5, 2000
Exhibit 10 Letter Regarding Relocation Arrangements Between PG&E
Corporation and Thomas B. King
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
Exhibit 27.1 Financial Data Schedule for the quarter ended
March 31, 2000, for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
March 31, 2000, for Pacific Gas and Electric
Company
(b) The following Current Reports on Form 8-K were filed during the first
quarter of 2000 and through the date hereof (2):
1. January 21, 2000
Item 5. Other Events
A. Pacific Gas and Electric Company's General Rate Case
Proceeding
B. Proposed Auction of Pacific Gas and Electric Company's
Hydroelectric Generating Assets.
C. 1998 Annual Transition Cost Proceeding
- ---------------
(2) 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).
2. January 31, 2000
Item 5. Other Events
Sale of Texas Gas Transmission Companies
3. February 23, 2000
Item 5. Other Events
A. Pacific Gas and Electric Company's General Rate Case
Proceeding
B. 1998 Annual Transition Cost Proceeding
C. Disposition of PG&E Energy Services Corporation
4. April 14, 2000
Item 5. Other Events
A. Pacific Gas and Electric Company's 2000 Cost of Capital
Proceeding
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
CHRISTOPHER P. JOHNS
By __________________________
CHRISTOPHER P. JOHNS
Vice President and Controller
PACIFIC GAS AND ELECTRIC COMPANY
KENT M. HARVEY
By __________________________
KENT M. HARVEY
Senior Vice President-Chief Financial
Officer, Controller and Treasurer
Dated: May 12, 2000
Exhibit Index
Exhibit No. Description of Exhibit
Exhibit 3.1 Restated Articles of Incorporation of PG&E
Corporation, dated as of May 5, 2000
Exhibit 3.2 Bylaws of PG&E Corporation, dated as of May 5, 2000
Exhibit 10 Letter Regarding Relocation Arrangements Between PG&E
Corporation and Thomas B. King
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratio of Earnings to Fixed Charges for
Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas
and Electric Company
Exhibit 27.1 Financial Data Schedule for the quarter ended
March 31, 2000 for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
March 31, 2000 for Pacific Gas and Electric Company