FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
----------------------------------
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 October 26, 2000:
PG&E Corporation 387,095,350 shares
Pacific Gas and Electric Company Wholly owned by PG&E Corporation
PG&E CORPORATION
FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000
TABLE OF CONTENTS
PAGE
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
CONDENSED CONSOLIDATED INCOME STATEMENT.................1
CONDENSED CONSOLIDATED BALANCE SHEET....................3
STATEMENT OF CONDENSED CONSOLIDATED CASH FLOWS .........5
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED INCOME STATEMENT.................6
CONDENSED CONDSOLIDATED BALANCE SHEET...................7
STATEMENT OF CONDENSED CONSOLIDATED CASH FLOWS..........9
NOTE 1: GENERAL..........................................10
NOTE 2: THE CALIFORNIA ELECTRIC INDUSTRY.................11
NOTE 3: RISK MANAGEMENT AND FINANCIAL INSTRUMENTS........21
NOTE 4: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING
SOLELY UTILITY SUBORDINATED EBENTURES............23
NOTE 5: DIVESTITURES.....................................24
NOTE 6: COMMITMENTS AND CONTINGENCIES....................25
NOTE 7: SEGMENT INFORMATION..............................29
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS. ....................32
THE CALIFORNIA ELECTRIC INDUSTRY..........................34
PG&E NATIONAL ENERGY GROUP................................44
REGULATORY MATTERS........................................46
RESULTS OF OPERATIONS.....................................49
LIQUIDITY AND FINANCIAL RESOURCES.........................55
ENVIRONMENTAL MATTERS.....................................59
RISK MANAGEMENT ACTIVITIES................................59
LEGAL MATTERS.............................................60
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES..................60
ABOUT MARKET RISK
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS.........................................61
ITEM 5. OTHER INFORMATION.........................................61
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K..........................61
SIGNATURE..........................................................63
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
- ----------------------------------------------------
PG&E CORPORATION
CONDENSED CONSOLIDATED INCOME STATEMENT
(in millions, except per share amounts)
Three months ended Nine months ended
September 30, September 30,
2000 1999 (1) 2000 1999 (1)
-------- -------- -------- --------
Operating revenues
Utility $ 2,523 $ 2,587 $ 7,037 $ 6,905
Energy commodities and services 4,981 3,630 11,113 9,120
-------- -------- -------- --------
Total operating revenues 7,504 6,217 18,150 16,025
Operating expenses
Cost of energy for utility 2,234 864 4,187 2,183
Deferred electric procurement costs (2,176) - (2,789) -
Cost of energy commodities and services 4,618 3,394 10,137 8,415
Operating and maintenance 960 765 2,420 2,294
Depreciation, amortization and decommissioning 1,239 678 2,268 1,676
-------- -------- -------- --------
Total operating expenses 6,875 5,701 16,223 14,568
-------- -------- -------- --------
Operating income 629 516 1,927 1,457
Interest expense, net 191 190 556 583
Other income, net 45 20 72 81
-------- -------- -------- --------
Income before income taxes 483 346 1,443 955
Income taxes 239 149 671 395
-------- -------- -------- --------
Income from continuing operations 244 197 772 560
Discontinued operations
Loss from operations of PG&E Energy Services
(net of applicable income taxes of
$9 million and $26 million, respectively) - (12) - (34)
Loss on disposal of PG&E Energy Services
(net of applicable incomes taxes of
$13 million) (19) - (19) -
-------- -------- -------- --------
Income before cumulative effect of change 225 185 753 526
in accounting principle
Cumulative effect of change in accounting
principle (net of applicable income taxes
of $8 million) - - - 12
-------- -------- -------- --------
Net income $ 225 $ 185 $ 753 $ 538
======== ======== ======== ========
Weighted Average Common Shares Outstanding 362 367 361 369
Earnings per common share, basic
Income from continuing operations $ .67 $ .53 $ 2.14 $ 1.52
Discontinued operations (.05) (.03) (.05) (.09)
Cumulative effect of accounting change - - - .03
-------- -------- -------- --------
$ .62 $ .50 $ 2.09 $ 1.46
======== ======== ======== ========
Earnings per common share, diluted
Income from continuing operations $ .67 $ .53 $ 2.12 $ 1.51
Discontinued operations (.05) (.03) (.05) (.09)
Cumulative effect of accounting change - - - .03
-------- -------- -------- --------
$ .62 $ .50 $ 2.07 $ 1.45
======== ======== ======== ========
Dividends declared per common share $ .30 $ .30 $ .90 $ .90
<FN>
The accompanying Notes to 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. Operating income previously reported for the third quarter of 1999 was $492 million.
Net income previously reported for the third quarter of 1999 was $183 million ($0.50 per share).
</TABLE
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
-----------------------------
September 30, December 31,
2000 1999
------------ -----------
ASSETS
Current assets
Cash and cash equivalents $ 304 $ 281
Short-term investments 819 187
Accounts receivable
Customers, net 1,641 1,486
Energy marketing 1,187 532
Price risk management 776 607
Inventories and prepayments 987 598
Deferred income taxes - 133
-------- -------
Total current assets 5,714 3,824
Property, plant, and equipment
Utility 23,201 23,001
Non-utility
Electric generation 1,976 1,905
Gas transmission 2,522 2,541
Construction work in progress 686 436
Other 151 184
-------- -------
Total property, plant, and equipment (at original cost) 28,536 28,067
Accumulated depreciation and decommissioning (11,485) (11,291)
-------- --------
Property, plant, and equipment, net 17,051 16,776
Other noncurrent assets
Regulatory assets 6,726 4,957
Nuclear decommissioning funds 1,385 1,264
Other 3,015 2,894
-------- --------
Total noncurrent assets 11,126 9,115
-------- --------
TOTAL ASSETS $ 33,891 $ 29,715
======== ========
<FN>
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of
this statement.
</TABLE
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
---------------------------
September 30, December 31,
2000 1999
------------ -----------
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 2,369 $ 1,499
Current portion of long-term debt 616 592
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 2,002 708
Other 315 559
Regulatory balancing accounts 24 384
Energy marketing 1,234 480
Accrued taxes - 211
Price risk management 646 575
Other 1,182 1,033
-------- --------
Total current liabilities 8,678 6,331
Noncurrent liabilities
Long-term debt 6,512 6,673
Rate reduction bonds 1,817 2,031
Deferred income taxes 3,628 3,147
Deferred tax credits 162 231
Other 4,920 3,636
-------- --------
Total noncurrent liabilities 17,039 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, 386,703,729 and 384,406,113 shares, respectively 5,958 5,906
Common stock held by subsidiary, at cost, 23,815,500 shares (690) (690)
Reinvested earnings 2,126 1,670
-------- --------
Total common stockholders' equity 7,394 6,886
Commitments and contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 33,891 $ 29,715
======== ========
<FN>
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of
this statement.
PG&E CORPORATION
STATEMENT OF CONDENSED CONSOLIDATED CASH FLOWS (in millions)
For the nine months ended
September 30,
2000 1999
---------- ----------
Cash flows from operating activities
Net income $ 753 $ 538
Adjustments to reconcile net income to net cash
provided by operating activities:
Loss on disposal of businesses 19 -
Depreciation, amortization and decommissioning 2,268 1,684
Deferred electric procurement costs (2,789) -
Deferred income taxes and tax credits-net 545 (652)
Other deferred charges and noncurrent liabilities 861 (729)
Cumulative effect of change in accounting principle - (12)
Changes in operating assets and liabilities,net of effect
of discontinued operations:
Short-term investments (632) 18
Accounts receivable - trade (810) (225)
Regulatory balancing accounts payable (360) 855
Inventories and prepayments (194) 36
Price risk management assets and liabilities, net (98) 22
Accounts payable - trade 1,294 (224)
Accrued taxes (211) 309
Other working capital 536 64
Other-net 28 339
--------- ---------
Net cash provided by operating activities 1,210 2,023
--------- ---------
Cash flows from investing activities
Capital expenditures (1,220) (1,058)
Net proceeds from sales of businesses 103 1,014
Other-net (316) 108
--------- ---------
Net cash provided by investing activities (1,433) 64
--------- ---------
Cash flows from financing activities
Net borrowings (repayments) under credit facilities 894 (682)
Long-term debt matured, redeemed, or repurchased (432) (611)
Long-term debt issued 57 -
Common stock issued 52 44
Common stock repurchased - (534)
Dividends paid (325) (335)
Other-net - 14
--------- ---------
Net cash provided by financing activities 246 (2,104)
--------- ---------
Net change in cash and cash equivalents 23 (17)
Cash and cash equivalents at January 1 281 286
--------- ---------
Cash and cash equivalents at September 30 $ 304 $ 269
========= =========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 471 $ 518
Income taxes (net of refunds) $ 23 $ 589
<FN>
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of
this statement.
</TABLE
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED INCOME STATEMENT (in millions)
Three months ended Nine months ended
September 30, September 30,
2000 1999 2000 1999
-------- -------- -------- --------
Operating revenues
Electric utility $ 1,999 $ 2,189 $ 5,401 $ 5,550
Gas utility 524 398 1,636 1,355
-------- -------- -------- --------
Total operating revenues 2,523 2,587 7,037 6,905
Operating expenses
Cost of electric energy 2,056 746 3,544 1,681
Deferred electric procurement costs (2,176) - (2,789) -
Cost of gas 178 118 643 502
Operating and maintenance, 730 615 1,824 1,849
Depreciation, amortization, and decommissioning 1,202 622 2,160 1,513
-------- -------- -------- --------
Total operating expenses 1,990 2,101 5,382 5,545
-------- -------- -------- --------
Operating income 533 486 1,655 1,360
Interest expense, net 150 148 435 450
Other income, net 30 8 47 30
-------- -------- -------- --------
Income before income taxes 413 346 1,267 940
Income taxes 196 161 594 424
-------- -------- -------- --------
Net income 217 185 673 516
Preferred dividend requirement 6 6 18 18
-------- -------- -------- --------
Income available for common stock $ 211 $ 179 $ 655 $ 498
======== ======== ======== ========
<FN>
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of
this statement.
</TABLE
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
---------------------------
September 30, December 31,
2000 1999
------------ -----------
ASSETS
Current assets
Cash and cash equivalents $ 68 $ 80
Short-term investments 242 21
Accounts receivable, net 1,327 1,210
Inventories 283 294
Prepayments 56 34
Income tax receivable 295 -
Deferred income taxes - 119
--------- ---------
Total current assets 2,271 1,758
Property, plant, and equipment
Electric 15,718 15,762
Gas 7,483 7,239
Construction work in progress 228 214
--------- ---------
Total property, plant, and equipment (at original cost) 23,429 23,215
Accumulated depreciation and decommissioning (10,616) (10,497)
--------- ---------
Property, plant, and equipment, net 12,813 12,718
Other noncurrent assets
Regulatory assets 6,650 4,895
Nuclear decommissioning funds 1,385 1,264
Other 1,064 835
-------- --------
Total noncurrent assets 9,099 6,994
-------- --------
TOTAL ASSETS $ 24,183 $ 21,470
======== ========
<FN>
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of
this statement.
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEET (in millions)
Balance at
---------------------------
September 30, December 31,
2000 1999
------------ -----------
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 917 $ 449
Current portion of long-term debt 399 465
Current portion of rate reduction bonds 290 290
Accounts payable
Trade creditors 1,859 577
Related parties 27 216
Regulatory balancing accounts 24 384
Other 347 333
Accrued taxes - 118
Deferred income taxes 10 -
Other 644 529
-------- -------
Total current liabilities 4,517 3,361
Noncurrent liabilities
Long-term debt 4,866 4,877
Rate reduction bonds 1,817 2,031
Deferred income taxes 2,991 2,510
Deferred tax credits 161 231
Other 3,606 2,252
------- -------
Total noncurrent liabilities 13,441 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, 19,481,213 and 7,627,765
shares, respectively (475) (200)
Additional paid in capital 1,971 1,964
Reinvested earnings 2,399 2,107
-------- --------
Total stockholders' equity 5,788 5,771
Commitments and contingencies (Notes 2 and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY 24,183 $ 21,470
======== ========
<FN>
The accompanying Notes to 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 nine months ended
September 30,
2000 1999
----------- -----------
Cash flows from operating activities
Net income $ 673 $ 516
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, amortization, and decommissioning 2,160 1,513
Deferred electric procurement costs (2,789) -
Deferred income taxes and tax credits-net 540 (799)
Other deferred charges and noncurrent liabilities 640 (496)
Net effect of changes in operating assets and liabilities:
Short-term investments (221) (3)
Accounts receivable (117) 128
Regulatory balancing accounts payable (360) 855
Inventories and prepayments (306) 12
Accounts payable - trade 1,093 (100)
Accrued taxes (118) 231
Other working capital 122 (10)
Other-net (20) 76
--------- ---------
Net cash provided by operating activities 1,297 1,923
--------- ---------
Cash flows from investing activities
Capital expenditures (874) (848)
Proceeds from sale of assets - 1,014
Other-net 38 21
--------- ---------
Net cash used by investing activities (836) 187
--------- ---------
Cash flows from financing activities
Net borrowings (repayments) under credit facilities 468 (591)
Long-term debt matured, redeemed, or repurchased (291) (474)
Common stock repurchased (275) (725)
Dividends paid (375) (309)
--------- ---------
Net cash used by financing activities (473) (2,099)
--------- ---------
Net change in cash and cash equivalents (12) 11
Cash and cash equivalents at January 1 80 73
--------- ---------
Cash and cash equivalents at September 30 $ 68 $ 84
======== ========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 295 $ 363
Income taxes (net of refunds) $ - $ 852
<FN>
The accompanying Notes to Condensed Consolidated Financial Statements are an integral part of
this statement.
</TABLE
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 Condensed Consolidated Financial
Statements and Notes to Condensed 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 condensed 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 PG&E National Energy Group.
Beginning January 1, 1999, the costs of major maintenance and overhauls,
principally at PG&E Generating Company (PG&E Gen), 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 of $8 million,
reflecting the cumulative effect of the change in accounting principle. 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.
PG&E Corporation expects to adopt Statement of Financial Accounting
Standards (SFAS) No. 133, as amended by SFAS No. 138, effective January 1,
2001. The Statement will require that the Company 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. The
Corporation currently is evaluating what the effect of SFAS No. 133 will be on
the earnings and financial position of PG&E Corporation. However, the mark-
to-market method of accounting is already applied for commodity non-hedging
and risk management activities.
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 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 independent power generators and 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.
An Independent System Operator (ISO) and a Power Exchange (PX) operate in
California. The PX provides a 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 and operates the real-
time and ancillary services markets for electricity. (Ancillary services are
needed to maintain the reliability of the electric grid.) The Utility
continues to own and maintain its transmission system, but the ISO controls
the operation of the system. During the transition period, the Utility is
required to bid or schedule into the PX and ISO markets all of the
electricity generated by its power plants and electricity acquired under
contractual agreements with unregulated generators. On August 3, 2000, the
California Public Utilities Commission (CPUC) authorized the Utility to
purchase energy and ancillary services and capacity products for retail
customers in wholesale markets outside the PX and to set up memorandum
accounts to track related costs. Such transactions are confined to previous
limits established for forward market purchases and must expire before
December 31, 2005.
Competitive Market Framework
- ----------------------------
Beginning in June 2000, the Utility has experienced unanticipated and
massive increases (above the generation-related costs component embedded in
frozen rates) in the wholesale costs of the electric energy that is purchased
from the PX on behalf of its retail customers. The average price that the PX
charged the Utility for electric power in the months of June, July, August,
and September 2000, was approximately 16.3 cents per kilowatt-hour (kWh), 11.0
cents per kWh, 18.7 cents per kWh and 14.0 cents per kWh, respectively,
compared to 3.0, 3.9, 4.1 and 4.0 cents per kWh for the same months in 1999.
The generation-related cost component that is embedded in frozen rates and
available for payment of wholesale electric power costs during those same
periods was approximately 5.4 cents per kWh. The forward curve for power
prices in the California market suggests that these costs may remain well
above the embedded cost component of frozen rates through the end of this year
and beyond next summer unless significant changes occur in the wholesale power
market.
As a result, the Utility has incurred and continues to incur expenses
representing the excess of power purchase costs above the generation component
embedded in frozen rates. Such expenses are deferred to a regulatory balancing
account called the Transition Revenue Account (TRA). The TRA balance as of
September 30, 2000 was approximately $2.9 billion. The TRA balance does not
reflect the Utility's revenues from (1) sales of energy from retained
generation facilities to the PX in excess of authorized costs or (2) the
amount by which the PX prices exceed the purchase price contained in the
Utility's long-term contracts to purchase energy from Qualifying Facilities
(QF) and other power providers. Approximately half of the Utility's suppliers
under QF contracts have elected to receive PX based prices for energy in
addition to contractual capacity payments. The Utility expects that most
remaining QF generators will elect to receive PX prices for their energy
payments by summer 2001. The Utility pays these suppliers directly, rather
than through the PX, but receives billing credits for energy delivered to the
PX from QFs.
A prior CPUC decision would prohibit the Utility from collecting after the
transition period certain electric costs incurred during the transition period
but not recovered from frozen rates during that period, including TRA under-
collections. The CPUC decision also would prohibit offsetting these specific
under-collected balances against over-collected transition costs. The Utility
is seeking judicial review by the California Supreme Court. The Utility's
petition is pending.
On October 4, 2000, the Utility and Southern California Edison Company filed
separate emergency petitions with the CPUC to rescind and modify as necessary
prior decisions prohibiting utilities from carrying over costs incurred during
the rate freeze to the post-rate freeze period. The utilities noted that many
parties have acknowledged that the wholesale electric power market is not
workably competitive and that the significant increases in prices were not
considered in the CPUC's original rulings. On October 17, 2000, the
administrative law judge (ALJ) and the CPUC commissioner assigned to review
the emergency petitions issued a joint ruling indicating that they would
reconsider the accounting mechanisms established in prior CPUC decisions and
adopt a schedule that permits a decision by the end of the year.
In response to the above ruling, the Utility filed its proposals requesting
that the CPUC modify its prior decisions to authorize the utilities to
transfer any unrecovered balance in the TRA as of the end of the rate freeze
into a new balancing account, and authorize recovery of the balance in that
new account over a period not to exceed four years, subject to a rate
stabilization plan to be addressed in a second phase of the proceeding. The
Utility asked the CPUC to adopt an expedited procedural schedule in a second
phase that would, not later than March 31, 2001, resolve the following issues:
(1) implementation of when and how the rate freeze is to be ended; (2)
adoption of post rate freeze tariffs and rates; (3) approval of the rate
stabilization plan; and (4) adoption of the retail rate components for
recovery of the new balancing account. The Utility indicated that it will
submit its detailed proposals on the rate stabilization plan and tariffs by
November 15, 2000.
At the prehearing conference held on October 27, 2000, the ALJ indicated
that the scope of the proceeding was solely to consider accounting mechanisms
to reduce the TRA under-collections and that the Utility's proposals for
interim relief were broader than contemplated in the October 17th ruling, were
not consistent with the CPUC's prior decisions precluding carryover of under-
collected TRA costs, and would not be considered in the proceeding before the
end of the year. However, the ALJ indicated that the CPUC would consider
proposals made by The Utility Reform Network (TURN), a consumer group, to
transfer TRA under-collections to the Transition Cost Balancing Account (TCBA)
discussed below. TURN's proposals would treat under-collected electric
procurement costs for accounting purposes as if such costs were unrecovered
transition costs, the likely effect of which would be to delay the completion
of transition cost recovery by the Utility as well as delay the end of the
rate freeze. If TURN's proposal were adopted, the Utility would have to write-
off any unrecovered transition costs remaining in the TCBA if such costs were
not probable of recovery. The ALJ ordered the parties to respond to the
utilities' emergency petitions and to TURN's proposal by November 9, 2000.
The Utility reviews on an ongoing basis the facts and circumstances relating
to the TRA under-collections. The Utility currently believes recovery of the
TRA under-collections is probable. TRA under-collections are recorded as a
regulatory asset on the balance sheet rather than being charged to earnings
because it is probable that these under-collections will be recovered through
the ratemaking process. However, ultimate recovery is dependent upon the
favorable outcome of the regulatory actions described above, as well as upon
other factors such as future market prices of electricity and future fuel
prices that, in part, are influenced by sales level, and economic conditions,
about which there can be no certainty. If regulatory or judicial relief is not
forthcoming, and if the Utility determines that its uncollected wholesale
power purchase costs are not probable of recovery, then the Utility would be
required to write off the unrecoverable portion as a charge against earnings.
In addition, the Utility would be unable to continue deferring these costs
incurred during the transition period and such expenses would reduce the
Utility's future earnings accordingly. With respect to wholesale power
purchase costs incurred after the end of the transition period and prior to
any adjustment in rates, the Utility may be able to defer these costs if it
determines that they are probable of recovery.
The Utility is actively exploring ways to reduce its exposure to the higher
power purchase costs and its corresponding TRA balance, including working with
interested parties to address power market dysfunction before appropriate
regulatory bodies and hedging a portion of its open procurement position
against higher purchase power costs through forward purchases. The CPUC only
recently authorized the Utility to enter into bilateral power purchase
contracts. In October 2000, the Utility entered into bilateral power purchase
contracts with several suppliers.
On October 16, 2000, the Utility joined with Southern California Edison and
TURN in filing a petition with the Federal Energy Regulatory Commission (FERC)
requesting that the FERC (1) immediately find the California wholesale
electricity market to be not workably competitive and the resulting prices to
be unjust and unreasonable; (2) immediately impose a cap on the price for
energy and ancillary services; and (3) institute further expedited proceedings
regarding the market failure, mitigation of market power, structural
solutions, and responsibility for refunds. However, the reduced price cap
requested, even if approved, would still be above the approximate 5.4 cents
per kWh embedded in frozen rates for the payment of the Utility's wholesale
power purchase costs. Also, on October 20, 2000, the ISO filed a market
stabilization plan with the FERC requesting the FERC to impose a price cap of
$100 per megawatt-hour (Mwh) (10 cents per kWh) for generators who do not
enter into contracts to supply 70 percent of their supply to serve California
customers. There are certain other exemptions to the $100 price cap. The
existing $250 price cap per Mwh hour (25 cents per kWh) would apply to
generators who are exempt from the $100 per Mwh hour price cap. The ISO also
has recommended that buyers (utilities) be required to contract for 85 percent
of their customer requirements for power in advance of when the power is
needed. Further, the ISO has adopted additional load based price caps for the
real-time and ancillary service markets which would range between $65 and $250
per Mwh. These price caps would begin as soon as November 3, 2000, and remain
in place until real-time and ancillary service markets have demonstrated that
they are workably competitive under a variety of load conditions.
A Joint Resolution of the California legislature called on the CPUC
to initiate an investigation to review the impact of the current electricity
crisis on consumers and California investor-owned utilities with emphasis on
the options for correcting the electricity market, methods to eliminate price
volatility for consumers, and importantly, methods for cost recovery and cost
allocation. In response, the CPUC issued an order on September 7, 2000
expanding an existing investigation into the wholesale electric market and the
associated impact on electric rates to include the issues identified by the
legislature.
For the three and nine months ended September 30, 2000 and 1999, the cost
of electric energy for the Utility, reflected on the Condensed Consolidated
Income Statement, is comprised of the cost of fuel for electric generation
and QF purchases, the cost of PX purchases, and ancillary services charged by
the ISO, net of sales to the PX, as follows:
Three months ended Nine months ended
September 30, September 30,
2000 1999 2000 1999
-------- -------- -------- --------
(in millions)
Cost of fuel for electric generation and
QF purchases $ 592 $ 409 $ 1,203 $ 1,178
Cost of purchases from the PX and ISO 2,132 554 3,492 1,101
Proceeds from sales to the PX (668) (217) (1,151) (598)
-------- -------- -------- --------
Total Utility cost of electric energy $ 2,056 $ 746 $ 3,544 $ 1,681
======== ======== ======== ========
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 industry structure. The transition period ends the
earlier of December 31, 2001, or when the particular utility has recovered its
eligible 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.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public
purpose programs, nuclear decommissioning, rate reduction bond debt service,
and the cost of procuring electricity for the Utility's retail customers. 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, fluctuating PX energy prices,
and certain other factors. The CTC is collected regardless of the customer's
choice of electricity supplier (i.e., the CTC is non-bypassable).
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 the 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.
Revenues generated from the Utility's sales to the PX and ISO that exceed
authorized costs are also used to offset transition costs.
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.
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 long-term agreements with non-utility generators to
purchase electric power at fixed prices. Prices fixed under these contracts
have generally been 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. The contracts expire at various
dates through 2028. 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. To the extent that the contracted prices are
below the market price, the Utility is using the savings to offset other
transition costs during the transition period.
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 nine months ended September
30, 2000 and 1999, the average price paid under the Utility's long-term
contracts for electricity was 7.8 cents and 6.4 cents per kWh, respectively.
At September 30, 2000, and December 31, 1999, the Utility's net generation-
related regulatory assets (excluding the TRA) totaled $2.6 billion and $4.0
billion, respectively. Included in the generation-related regulatory assets
at September 30, 2000, is $2.1 billion associated with the valuation of the
Utility's hydroelectric generation facilities (discussed below), a regulatory
asset related to the rate reduction bonds of approximately $1.1 billion, and a
credit balance of $0.6 billion in balancing account called the Transition Cost
Balancing Account (TCBA) which tracks the amount of transition costs that must
be recovered. These generation-related regulatory assets decreased by $1.4
billion for the nine months ended September 30, 2000, and decreased $955
million for the nine months ended September 30, 1999.
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 has been 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. Beginning January 1, 1998, the Utility started
collecting these eligible transition costs through the non-bypassable CTC,
market valuation of generation assets in excess of book value,
and energy sales from the Utility's electric generation facilities prior to
market valuation. Further, transition costs are reduced by the amount that
contract prices to purchase power from QFs and other providers are lower than
the PX price.
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 currently is reviewing non-nuclear transition costs amortized from
July 1, 1998, to June 30, 1999.
Under the electric industry restructuring law, when the Utility has
recovered all of its transition costs the conditions for terminating the rate
freeze and ending the transition period will have been satisfied. On August
9, 2000, a settlement agreement was filed by the Utility and others with the
CPUC regarding the valuation and disposition of the Utility's hydroelectric
assets, specifying that the value of those assets for purpose of transition
cost calculation is $2.8 billion.
At August 31, 2000, consistent with transition cost recovery procedures
adopted by the CPUC, the Utility credited its TCBA by $2.1 billion, the amount
by which the value of the hydroelectric generating assets exceeded the
aggregate book value of such assets. The Utility also established a separate
regulatory asset in the same amount. The accounting entries were based on the
value used in the proposed settlement discussed above. Based on the credit
made to the TCBA, the Utility would have completed collection of all
transition costs that must be collected during the transition period as of
August 2000. If the hydroelectric assets were to be sold or valued at a
higher amount, the Utility's transition costs would have been recovered as of
an earlier date. Testimony taken to date in the CPUC proceeding in which
valuation is to be established put the range of market values from $2.4
billion to in excess of $3 billion under operating and market conditions prior
to June 2000. On October 16, 2000, the CPUC issued a ruling re-opening the
proceeding to obtain more information from parties about market valuation in
light of the different market conditions experienced during the summer of
2000. That new testimony is to be submitted in December 2000 with further
testimony and evidentiary hearings scheduled for next year. The accounting
entries discussed above are subject to later adjustment based on the final
valuation of the hydroelectric assets adopted by the CPUC.
Under the electric industry restructuring law, after the Utility recovers
its transition costs, the Utility's retail customers assume responsibility
for wholesale energy costs. Actual changes in customer rates will not occur
until the Utility files for new retail rates and the CPUC authorizes them.
During the transition period, the Utility is required to continue to use the
transition period accounting mechanisms, discussed above. This requires that
revenues from sales to the PX of Utility-owned generation and generation from
QFs and other providers in excess of costs be credited to the TCBA. In
addition, the TCBA balance includes a credit for the amount of PX revenues
from the Utility's sale of generation from the Diablo Canyon nuclear power
plant to the PX that exceed revenues from the fixed Incremental Cost Incentive
Price (ICIP). (During 2000, the ICIP is 3.43 cents per kWh.) After
taking into account the credit for the hydroelectric assets described
above, at September 30, 2000, the Utility's TCBA had a credit balance of
approximately $585 million. As mentioned above, the CPUC has issued a ruling
indicating that it would reconsider certain of these accounting mechanisms
noting that the CPUC has the authority to implement any necessary changes to
the electric restructuring accounting provisions and cost recovery consistent
with statutory requirements.
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 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 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 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.
As discussed above, on August 9, 2000, the Utility and a number of
interested parties filed an application with the CPUC requesting that the
CPUC approve a settlement agreement reached by these parties in the Utility's
proceeding to determine the market value of its hydroelectric generation
assets. In this settlement agreement, the Utility indicated that it would
transfer its hydroelectric generation assets, at a value of $2.8 billion, to
an affiliate (referred to herein as PG&E CalHydro) that would not be subject
to cost of service regulation by the CPUC.
PG&E CalHydro would hold and operate the assets, subject to a 40-year
revenue sharing agreement (RSA) between PG&E CalHydro and the Utility. Under
the RSA, PG&E CalHydro would be allowed to recover an authorized inflation-
indexed operations and maintenance allowance, certain other expenses
including an allowance for capital additions, and a return on capital
investment. The return on equity (ROE) initially would be set at 12.50
percent and would be subject to an indexed adjustment trigger. Under the
RSA, 90 percent of the after-tax earnings received in excess of the agreed-
upon costs (including the target ROE) would be returned to the Utility to be
used as a credit against current costs charged to the Utility's distribution
ratepayers. If market revenues were insufficient to recover the agreed-upon
costs of operating the hydroelectric facilities (including the target ROE)
over a multi-year period, 90 percent of the revenue shortfalls would be
charged to the Utility to be recovered from distribution customers.
The RSA would become effective on the date that the CPUC order approving the
settlement and the RSA becomes final and non-appealable, subject to
termination by either the Utility or PG&E CalHydro in certain circumstances.
The CPUC may accept the settlement or reject it, suggest changes to it, or
adopt a different valuation approach. In addition, the transfer of the assets
from the Utility to PG&E CalHydro will require the approval of the FERC.
At September 30, 2000, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $700 million. The above
settlement, if approved, would result in a pre-tax charge of $2.1 billion. If
the value of the hydroelectric generation assets is determined by any method
other than a sale of the assets to an unrelated third party, 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. The CPUC is not likely to consider the Utility's proposed
settlement until next year, and it is uncertain at this time whether the
settlement will be approved, modified or rejected, or withdrawn.
Post-Transition Period
- ----------------------
The CPUC has established the Purchased Electric Commodity Account (PECA)
for the Utility to track energy costs after the rate freeze and transition
period end. In June 2000, the CPUC issued a decision in the second phase of
the Utility's post-transition period electric ratemaking proceeding. Among
other things, the CPUC determined that the PECA would reflect a pass-through
of energy costs, possibly subject to after-the-fact reasonableness reviews.
After the rate freeze ends, Diablo Canyon will be operated as a competitive
generator of electricity with revenues generated from prevailing market
rates. During the rate freeze, Diablo Canyon's operating costs have been
recovered through the incremental cost incentive price (ICIP) mechanism. 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.
As required by a prior CPUC decision on June 30, 2000, the Utility filed an
application with the CPUC requesting approval of its proposal for sharing
with ratepayers 50 percent of the post-rate freeze net benefits of operating
Diablo Canyon. The net benefit sharing methodology proposed in the Utility's
application would be effective at the end of the current electric rate freeze
for the Utility's customers and would continue for as long as the Utility
owned Diablo Canyon. Under the proposal, the Utility would share the net
benefits of operating Diablo Canyon based on the audited profits from
operations, determined consistent with the prior CPUC decisions. If Diablo
Canyon experiences losses, such losses would be accrued and netted against
profits in the calculation of the net benefits in subsequent periods (or
against profits in prior periods if subsequent profits are insufficient
to offset such losses). Any changes to the net sharing methodology must be
approved by the CPUC.
Future Competition
- ------------------
Opening California's electric generation to competition has raised certain
interest in introducing further competition in the electric industry. The
CPUC has opened a rulemaking proceeding to examine the various issues
associated with distributed generation. Distributed generation enables the
siting of electric generation technologies in close proximity to electric
demand, and raises issues about stranded costs (both within distribution and
transmission systems), interconnection charges, and cost allocation. The CPUC
staff has issued a report identifying options for possible CPUC consideration
regarding the additional unbundling of the electric distribution function and
evaluate the investor-owned utilities' role of default provider of
electricity.
It is too early to predict what may come of these matters. PG&E
Corporation is unable to predict when these issues will be addressed by the
CPUC or whether the results will have any impact on the Utility.
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 September 30, 2000 and 1999.
Short and long positions pertaining to derivative contracts used for hedging
activities as of September 30, 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 - September 30, 2000
Swaps 2.07 1.91 6
Options 0.45 0.34 8
Futures 0.08 0.12 3
Forward Contracts 3.00 2.03 22
Non-Hedging Activities - September 30, 1999
Swaps 3.18 3.14 7
Options 1.13 0.99 5
Futures 0.29 0.30 2
Forward Contracts 1.95 1.59 12
(1) One MMBtu is equal to one million British thermal units. PG&E
Corporation's electric power contracts, measured in megawatts, were converted
to MMBtu equivalents using a conversion factor of 10 MMBtu's per 1 megawatt-
hour. PG&E Corporation's natural gas liquids contracts were converted to
MMBtu equivalents using an appropriate conversion factor for each type of
natural gas liquids product.
Volumes shown for swaps represent notional volumes that are used to
calculate amounts due under the agreements and do not represent volumes
exchanged. Moreover, notional amounts are indicative only of the volume of
activity and are not a measure of market risk.
PG&E Corporation's net gains (losses) on swaps, options, futures, and
forward contracts held during the three and nine months ended September 30,
2000 and 1999, are as follows:
Three months ended Nine months ended
September 30, September 30,
2000 1999 2000 1999
-------- -------- -------- -------
(in millions) $ 50 $ (7) $ 129 $ (5)
Options 8 30 70 (5)
Futures (31) (3) (55) (23)
Forward contras (4) (35) (57) 60
-------- -------- -------- --------
Net gain (loss) $23 $ (15) $ 87 $ 27
======== ======== ======== ========
The following table discloses the estimated fair values of risk management
assets and liabilities as of September 30, 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 September 30,
2000, and December 31, 1999.
Average Ending
Fair Value Fair Value
- ---------------------------------------------------------------------------
(in millions)
Non-hedging activities - September 30, 2000
Assets
Swaps $ 136 $ 153
Options 102 107
Futures 26 21
Forward Contracts 820 841
------ ------
Total $ 1,084 $ 1,122
Noncurrent portion $ 346
Current portion $ 776
Liabilities
Swaps $ 91 $ 53
Options 48 35
Futures 45 70
Forward Contracts 758 801
------ ------
Total $ 942 $ 959
Noncurrent portion $ 313
Current portion $ 646
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. The Utility primarily engages in hedging activities
which were immaterial for the three- and nine-month periods ended September
30, 2000 and 1999.
In valuing its electric power, natural gas, and natural gas liquid
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 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 $63.6 million at September 30,
2000.
The credit exposure of the five largest counterparties comprised
approximately $548 million of the total credit exposure associated with
financial instruments used to manage price risk. Counterparties considered
to be investment grade or higher comprise 86 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 disposal was accounted for as a
discontinued operation and PG&E Corporation's investment in PG&E ES was
written down to its then estimated net realizable value. In addition, PG&E
Corporation provided a reserve for anticipated losses through the anticipated
date of sale. The total provision for discontinued operations was $58
million, net of income taxes of $36 million. During the second quarter of
2000, PG&E National Energy Group finalized a transaction related to the
disposal of PG&E ES commodity trading assets for $20 million, plus net working
capital of approximately $65 million, for a total of $85 million. In
addition, the sale of the Value-Added-Services business and various other
assets was completed on July 21, 2000, for a total consideration of $18
million. Both of these sales have working capital true-ups which will not be
finalized until 2001. For the three- and nine-months ended September 30,
2000, an additional estimated loss of $19 million (or $0.05 per share), net of
income taxes of $13 million was recorded. The PG&E ES business segment
generated net losses from operations of $34 million, net of income taxes of
$26 million for the nine-month period ended September 30, 1999.
On January 27, 2000, 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 PG&E
National Energy Group includes $279 million in cash, subject to adjustments
for working capital, debt repayment, and certain other items, as well as, the
assumption by El Paso of liabilities associated with PG&E GT Texas and debt
having a book value of $566 million.
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 fourth quarter 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 GT Texas 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 Condensed Consolidated Balance Sheet at September 30, 2000,
and December 31, 1999, are as follows:
September 30, December 31,
2000 1999
----------- -----------
(in millions)
Assets
Current assets $ 266 $ 229
Noncurrent assets 979 988
-------- --------
Total Assets 1,245 1,217
Liabilities
Current liabilities 589 448
Noncurrent liabilities 504 624
-------- --------
Total Liabilities 1,093 1,072
-------- --------
Net Assets $ 152 $ 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 $12 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 Matters
- ---------------------
Companies within the PG&E Corporation group 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 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.
Utility:
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 is
difficult to estimate. A change in estimate may occur in the near term due
to uncertainty concerning responsibility, the complexity of environmental
laws and regulations, and the selection of compliance alternatives.
At September 30, 2000, the Utility expects to spend $307 million for
hazardous waste remediation costs at identified sites, including divested
fossil-fueled power plants. The Utility had an accrued liability of $279
million and $271 million at September 30, 2000, and December 31, 1999,
respectively, representing the discounted value of these costs.
Of the $279 million accrued liability discussed above, the Utility has
recovered $154 million through rates, including $39 million through
depreciation, and expects to recover another $96 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 $480 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 the "Generation Divestiture" section of Note 2, the
Utility will retain the pre-closing remediation liability associated with
divested generation facilities.
The Utility believes the ultimate outcome of these matters will not have a
material impact on the Utility's financial position or results of operations.
PG&E National Energy Group:
USGen New England (USGenNE), a subsidiary of the PG&E National Energy Group
has a 760 MW coal-fired power plant in Salem, Massachusetts and a 1,586 MW
coal-fired in Somerset, Massachusetts (Brayton Point power plant). The
Commonwealth of Massachusetts is considering the adoption of more stringent
reductions in air emissions from electric generating facilities which is
expected to impact those plants. USGen NE, has proposed an emission reduction
plan that may include modernization of the plant in Salem and the use of
advanced technologies for emissions removal. USGenNE is also studying various
advanced technologies for emissions removal for the Brayton Point power plant.
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. On
September 15, 2000, USGenNE entered into a series of agreements with the
Massachusetts Department of Environmental Protection and CLF that address and
resolve the potential claims CLF identified in its April 18, 2000 letter. The
agreements require, among other things, that USGenNE alter its existing water
treatment facilities at both the Salem Harbor and Brayton Point power plants
by replacing certain unlined treatment basins; submit and implement a plan for
the closure of such basins; and perform certain environmental testing at the
facilities. The agreements are incorporated in a complaint, answer and
proposed judgment to which USGenNE and CLF agreed. The complaint, answer and
proposed judgment have been filed in federal court. On October 19, 2000, the
court entered the consent decree in the docket.
In May 2000, USGenNE received a request for information pursuant to Section
114 of the Clean Air Act from the U.S. Environmental Protection
Agency (EPA) seeking detailed operating and maintenance history for the
Salem Harbor and Brayton Point power plants. The Company believes that this
request for information is part of the EPA's industry-wide investigation of
coal-fired electric power generators to determine compliance with
environmental requirements under the Clean Air Act associated with repairs,
maintenance, modifications, and operational changes made to coal-fired
facilities over the years. If the EPA were to find that there were physical
changes made in the past that were undertaken without first receiving the
required permits under the Clean Air Act, then penalties may be imposed and
further emission reductions might be necessary at these plants. PG&E
Corporation believes the ultimate outcome of these matters will not have a
material impact on its 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 1,000 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 one of the class actions, opt-out notices were sent to approximately 159
Texas cities as potential class members and fewer than 20 cities opted out by
the deadline in 1997. In November 1999, the court dismissed 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. Certain of the 106
class members have elected to opt out of the settlement in 2000. In July
2000, the defendants effectuated a settlement with approximately 70 percent
of the class members pursuant to which the defendants paid an aggregate of
$6.3 million (inclusive of attorney's fees and expenses) in exchange for a
comprehensive release from past liabilities and a license to use city rights-
of-way for 25 years. In September 2000, the court approved a settlement as
to the remaining 21 plaintiffs in this case (who are also class members of
another pending class action lawsuit involving a third party). The
defendants paid approximately $4 million to these plaintiffs in exchange for
a comprehensive release from past liabilities and a license to use city
rights-of-way for 25 years. Settlement discussions are continuing with the
city of Corpus Christi and other Texas cities.
Efforts also continue in attempts to reach arrangements with other large
Texas cities, including San Antonio, Austin and Brownsville, regarding
potential liability of PG&E corporation-related Texas entities for the
possible unauthorized presence of pipe within city rights-of-way.
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 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 Statement of Financial Accounting Standards (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 $ 126 $ 70
Provisions for liabilities 27 27
Payments (27) (13)
----- -----
Ending balance, September 30, 2000 $ 126 $ 84
===== =====
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
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: 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). PG&E
Corporation has entered into an agreement to sell its Texas natural gas and
natural gas liquids business.
Segment information for the three and nine months ended September 30, 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)
For the three months ended September 30, 2000
Operating revenues $ 2,519 $ 287 $ 52 $ 241 $ 4,406 $ (1) $ 7,504
Intersegment revenues 4 3 12 17 371 (407) -
------- ------- ------- ------- ------- ------- -------
Total operating revenues 2,523 290 64 258 4,777 (408) 7,504
Income from
continuing operations 211 16 16 - 1 - 244
For the three months ended September 30, 1999
Operating revenues $ 2,584 $ 273 $ 42 $ 161 $ 3,151 $ 6 $ 6,217
Intersegment revenues 3 2 14 16 339 (374) -
------- ------- ------- ------- ------- ------- -------
Total operating revenues 2,587 275 56 177 3,490 (368) 6,217
Income from
continuing operations 179 21 18 (7) (17) 3 197
For the nine months ended September 30, 2000
Operating revenues $ 7,026 $ 877 $ 140 $ 661 $ 9,457 $ (11) $18,150
Intersegment revenues 11 6 37 46 1,036 (1,136) -
------- ------- ------- ------- ------- ------- -------
Total operating revenues 7,037 883 177 707 10,493 (1,147) 18,150
Income from
continuing operations 655 70 43 - 14 (10) 772
Total assets at
September 30, 2000 24,183 4,198 1,129 1,245 2,936 200 33,891
For the nine months ended September 30, 1999
Operating revenues $ 6,898 $ 814 $ 127 $ 871 $ 7,314 $ 1 $16,025
Intersegment revenues 7 4 39 99 831 (980) -
------- ------- ------- ------- ------- ------- -------
Total operating revenues 6,905 818 166 970 8,145 (979) 16,025
Income from
continuing operations 498 77 46 (39) (19) (3) 560
Total assets at
September 30, 1999 21,740 3,858 1,162 2,548 2,195 (17) 31,486
<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. PG&E
National Energy Group provides energy products and services throughout North
America.
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 (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). PG&E Corporation
has entered into an agreement to sell its Texas natural gas and natural gas
liquids 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 condensed 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 condensed 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 condensed 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:
- legislative or regulatory changes, including the pace and extent of the
ongoing restructuring of the electric and natural gas industries across the
United States;
- the amount and method of recovery from customers of the under-collected
electric procurement costs recorded in the Utility's TRA;
- what regulatory, judicial, and legislative actions may be taken to
mitigate the higher power prices;
- future sales levels and economic conditions;
- 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 and future fuel prices which, in
part, are influenced by future weather conditions and the availability of
hydroelectric power;
- the success of management's strategies to maximize shareholder value in
PG&E National Energy Group, which may include acquisitions or dispositions of
assets, or investments in emerging companies or new businesses;
- 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 outcome of the Utility's various regulatory proceedings, including
the proceeding to determine the value of the Utility's hydroelectric
generation assets, the electric transmission rate case applications, post-
transition period ratemaking proceedings, the 2001 attrition rate adjustment
request, the cost of capital application, and the 2002 General Rate Case;
- 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.
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 September 30, 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 CALIFORNIA ELECTRIC INDUSTRY
In 1998, California became one of the first states in the country to
implement electric industry restructuring and establish a 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 independent power generators and 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.
An Independent System Operator (ISO) and a Power Exchange (PX) operate in
California. The PX provides a 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 and operates the real-
time and ancillary services markets for electricity. (Ancillary services are
needed to maintain the reliability of the electric grid.) The Utility
continues to own and maintain its transmission system, but the ISO controls
the operation of the system. During the transition period, the Utility is
required to bid or schedule into the PX and ISO markets all of the
electricity generated by its power plants and electricity acquired under
contractual agreements with unregulated generators. On August 3, 2000, the
California Public Utilities Commission (CPUC) authorized the Utility to
purchase energy and ancillary services and capacity products for retail
customers in wholesale markets outside the PX and to set up memorandum
accounts to track related costs. Such transactions are confined to previous
limits established for forward market purchases and must expire before
December 31, 2005.
Competitive Market Framework
- ----------------------------
Beginning in June 2000, the Utility has experienced unanticipated and
massive increases (above the generation-related costs component embedded in
frozen rates) in the wholesale costs of the electric energy that is purchased
from the PX on behalf of its retail customers. The average price that the PX
charged the Utility for electric power in the months of June, July, August,
and September 2000, was approximately 16.3 cents per kilowatt-hour (kWh), 11.0
cents per kWh, 18.7 cents per kWh and 14.0 cents per kWh, respectively,
compared to 3.0, 3.9, 4.1 and 4.0 cents per kWh for the same months in 1999.
The generation-related cost component that is embedded in frozen rates and
available for payment of wholesale electric power costs during those same
periods was approximately 5.4 cents per kWh. The forward curve for power
prices in the California market suggests that these costs may remain well
above the embedded cost component of frozen rates through the end of this year
and beyond next summer unless significant changes occur in the wholesale power
market.
As a result, the Utility has incurred and continues to incur expenses
representing the excess of power purchase costs above the generation component
embedded in frozen rates. Such expenses are deferred to a regulatory balancing
account called the Transition Revenue Account (TRA). The TRA balance as of
September 30, 2000 was approximately $2.9 billion. The TRA balance does not
reflect the Utility's revenues from (1) sales of energy from retained
generation facilities to the PX in excess of authorized costs or (2) the
amount by which the PX prices exceed the purchase price contained in the
Utility's long-term contracts to purchase energy from Qualifying Facilities
(QF) and other power providers. Approximately half of the Utility's suppliers
under QF contracts have elected to receive PX based prices for energy in
addition to contractual capacity payments. The Utility expects that most
remaining QF generators will elect to receive PX prices for their energy
payments by summer 2001. The Utility pays these suppliers directly, rather
than through the PX, but receives billing credits for energy delivered to the
PX from QFs.
A prior CPUC decision would prohibit the Utility from collecting after the
transition period certain electric costs incurred during the transition period
but not recovered from frozen rates during that period, including TRA under-
collections. The CPUC decision also would prohibit offsetting these specific
under-collected balances against over-collected transition costs. The Utility
is seeking judicial review by the California Supreme Court. The Utility's
petition is pending.
On October 4, 2000, the Utility and Southern California Edison Company filed
separate emergency petitions with the CPUC to rescind and modify as necessary
prior decisions prohibiting utilities from carrying over costs incurred during
the rate freeze to the post-rate freeze period. The utilities noted that many
parties have acknowledged that the wholesale electric power market is not
workably competitive and that the significant increases in prices were not
considered in the CPUC's original rulings. On October 17, 2000, the
administrative law judge (ALJ) and the CPUC commissioner assigned to review
the emergency petition issued a joint ruling indicating that they would
reconsider the accounting mechanisms established in prior CPUC decisions and
adopt a schedule that permits a decision by the end of the year.
In response to the above ruling, the Utility filed its proposals requesting
that the CPUC modify its prior decisions to authorize the utilities to
transfer any unrecovered balance in the TRA as of the end of the rate freeze
into a new balancing account, and authorize recovery of the balance in that
new account over a period not to exceed four years, subject to a rate
stabilization plan to be addressed in a second phase of the proceeding. The
Utility asked the CPUC to adopt an expedited procedural schedule in a second
phase that would, not later than March 31, 2001, resolve the following issues:
(1) implementation of when and how the rate freeze is to be ended; (2)
adoption of post rate freeze tariffs and rates; (3) approval of the rate
stabilization plan; and (4) adoption of the retail rate components for
recovery of the new balancing account. The Utility indicated that it will
submit its detailed proposals on the rate stabilization plan and tariffs by
November 15, 2000.
At the prehearing conference held on October 27, 2000, the ALJ indicated
that the scope of the proceeding was solely to consider accounting mechanisms
to reduce the TRA under-collections and that the Utility's proposals for
interim relief were broader than contemplated in the October 17th ruling, were
not consistent with the CPUC's prior decisions precluding carryover of under-
collected TRA costs, and would not be considered in the proceeding before the
end of the year. However, the ALJ indicated that the CPUC would consider
proposals made by The Utility Reform Network (TURN), a consumer group, to
transfer TRA under-collections to the TCBA. TURN's proposals would treat
under-collected electric procurement costs for accounting purposes as if such
costs were unrecovered transition costs, the likely effect of which would be
to delay the completion of transition cost recovery by the Utility as well as
delay the end of the rate freeze. If TURN's proposal were adopted, the Utility
would have to write-off any unrecovered transition costs remaining in the TCBA
if such costs were not probable of recovery. The ALJ ordered the parties to
respond to the utilities' emergency petitions and to TURN's proposal by
November 9, 2000.
The Utility reviews on an ongoing basis the facts and circumstances relating
to the TRA under-collections. The Utility currently believes recovery of the
TRA under-collections is probable. TRA under-collections are recorded as a
regulatory asset on the balance sheet rather than being charged to earnings
because it is probable that these under-collections will be recovered through
the ratemaking process. However, ultimate recovery is dependent upon the
favorable outcome of the regulatory actions described above, as well as upon
other factors such as future market prices of electricity and future fuel
prices that, in part, are influenced by sales level, and economic conditions,
about which there can be no certainty. If regulatory or judicial relief is not
forthcoming, and if the Utility determines that its uncollected wholesale
power purchase costs are not probable of recovery, then the Utility would be
required to write off the unrecoverable portion as a charge against earnings.
In addition, the Utility would be unable to continue deferring these costs
incurred during the transition period and such expenses would reduce the
Utility's future earnings accordingly. With respect to wholesale power
purchase costs incurred after the end of the transition period and prior to
any adjustment in rates, the Utility may be able to defer these costs if it
determines that they are probable of recovery.
The Utility is actively exploring ways to reduce its exposure to the higher
power purchase costs and its corresponding TRA balance, including working with
interested parties to address power market dysfunction before appropriate
regulatory bodies and hedging a portion of its open procurement position
against higher purchase power costs through forward purchases. The CPUC only
recently authorized the Utility to enter into bilateral power purchase
contracts. In October 2000, the Utility entered into bilateral power purchase
contracts with several suppliers.
On October 16, 2000, the Utility joined with Southern California Edison and
TURN in filing a petition with the Federal Energy Regulatory Commission (FERC)
requesting that the FERC (1) immediately find the California wholesale
electricity market to be not workably competitive and the resulting prices to
be unjust and unreasonable; (2) immediately impose a cap on the price for
energy and ancillary services; and (3) institute further expedited proceedings
regarding the market failure, mitigation of market power, structural
solutions, and responsibility for refunds. However, the reduced price cap
requested, even if approved, would still be above the approximate 5.4 cents
per kWh embedded in frozen rates for the payment of the Utility's wholesale
power purchase costs. Also, on October 20, 2000, the ISO filed a market
stabilization plan with the FERC requesting the FERC to impose a price cap of
$100 per megawatt-hour (Mwh) (10 cents per kWh) for generators who do not
enter into contracts to supply 70 percent of their supply to serve California
customers. There are certain other exemptions to the $100 price cap. The
existing $250 price cap per Mwh hour (25 cents per kWh) would apply to
generators who are exempt from the $100 per Mwh hour price cap. The ISO also
has recommended that buyers (utilities) be required to contract for 85 percent
of their customer requirements for power in advance of when the power is
needed. Further, the ISO has adopted additional load based price caps for the
real-time and ancillary service markets which would range between $65 and $250
per Mwh. These price caps would begin as soon as November 3, 2000, and remain
in place until real-time and ancillary service markets have demonstrated that
they are workably competitive under a variety of load conditions.
A Joint Resolution of the California legislature called on the CPUC
to initiate an investigation to review the impact of the current electricity
crisis on consumers and California investor-owned utilities with emphasis on
the options for correcting the electricity market, methods to eliminate price
volatility for consumers, and importantly, methods for cost recovery and cost
allocation. In response, the CPUC issued an order on September 7, 2000
expanding an existing investigation into the wholesale electric market and the
associated impact on electric rates to include the issues identified by the
legislature.
For the three and nine months ended September 30, 2000 and 1999, the cost
of electric energy for the Utility, reflected on the Condensed Consolidated
Income Statement, is comprised of the cost of fuel for electric generation
and QF purchases, the cost of PX purchases, and ancillary services charged by
the ISO, net of sales to the PX, as follows:
Three months ended Nine months ended
September 30, September 30,
2000 1999 2000 1999
-------- -------- -------- --------
(in millions)
Cost of fuel for electric generation and
QF purchases $ 592 $ 409 $ 1,203 $ 1,178
Cost of purchases from the PX and ISO 2,132 554 3,492 1,101
Proceeds from sales to the PX (668) (217) (1,151) (598)
-------- -------- -------- --------
Total Utility cost of electric energy $ 2,056 $ 746 $ 3,544 $ 1,681
======== ======== ======== ========
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 industry structure. The transition period ends the
earlier of December 31, 2001, or when the particular utility has recovered its
eligible 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.
Revenues from frozen electric rates provide for the recovery of authorized
Utility costs, including transmission and distribution service, public
purpose programs, nuclear decommissioning, rate reduction bond debt service,
and the cost of procuring electricity for the Utility's retail customers. 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, fluctuating PX energy prices,
and certain other factors. The CTC is collected regardless of the customer's
choice of electricity supplier (i.e., the CTC is non-bypassable).
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 the 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.
Revenues generated from the Utility's sales to the PX and ISO that exceed
authorized costs are also used to offset transition costs.
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.
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 long-term agreements with non-utility generators to
purchase electric power at fixed prices. Prices fixed under these contracts
have generally been 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. The contracts expire at various
dates through 2028. 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. To the extent that the contracted prices are
below the market price, the Utility is using the savings to offset other
transition costs during the transition period.
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 nine months ended September
30, 2000 and 1999, the average price paid under the Utility's long-term
contracts for electricity was 7.8 cents and 6.4 cents per kWh, respectively.
At September 30, 2000, and December 31, 1999, the Utility's net generation-
related regulatory assets (excluding the TRA) totaled $2.6 billion and $4.0
billion, respectively. Included in the generation-related regulatory assets
at September 30, 2000, is $2.1 billion associated with the valuation of the
Utility's hydroelectric generation facilities (discussed below), a regulatory
asset related to the rate reduction bonds of approximately $1.1 billion, and a
credit balance of $0.6 billion in balancing account called the Transition Cost
Balancing Account (TCBA) which tracks the amount of transition costs that must
be recovered. These generation-related regulatory assets decreased by $1.4
billion for the nine months ended September 30, 2000, and decreased $955
million for the nine months ended September 30, 1999.
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 has been 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. Beginning January 1, 1998, the Utility started
collecting these eligible transition costs through the non-bypassable CTC,
market valuation of generation assetsin excess of book value,
and energy sales from the Utility's electric generation facilities prior to
market valuation. Further, transition costs are reduced by the amount that
contract prices to purchase power from QFs and other providers are lower than
the PX price.
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 currently is reviewing non-nuclear transition costs amortized from
July 1, 1998, to June 30, 1999.
Under the electric industry restructuring law, when the Utility has
recovered all of its transition costs the conditions for terminating the rate
freeze and ending the transition period will have been satisfied. On August
9, 2000, a settlement agreement was filed by the Utility and others with the
CPUC regarding the valuation and disposition of the Utility's hydroelectric
assets, specifying that the value of those assets for purpose of transition
cost calculation is $2.8 billion.
At August 31, 2000, consistent with transition cost recovery procedures
adopted by the CPUC , the Utility credited its TCBA by $2.1 billion, the
amount by which the value of the hydroelectric generating assets exceeded the
aggregate book value of such assets. The Utility also established a separate
regulatory asset in the same amount. The accounting entries were based on the
value used in the proposed settlement discussed above. Based on the credit
made to the TCBA, the Utility would have completed collection of all
transition costs that must be collected during the transition period as of
August 2000. If the hydroelectric assets were to be sold or valued at a
higher amount, the Utility's transition costs would have been recovered as of
an earlier date. Testimony taken to date in the CPUC proceeding in which
valuation is to be established put the range of market values from $2.4
billion to in excess of $3 billion under operating and market conditions prior
to June 2000. On October 16, 2000, the CPUC issued a ruling re-opening the
proceeding to obtain more information from parties about market valuation in
light of the different market conditions experienced during the summer of
2000. That new testimony is to be submitted in December 2000 with further
testimony and evidentiary hearings scheduled for next year. The accounting
entries discussed above are subject to later adjustment based on the final
valuation of the hydroelectric assets adopted by the CPUC.
Under the electric industry restructuring law, after the Utility recovers
its transition costs, the Utility's retail customers assume responsibility
for wholesale energy costs. Actual changes in customer rates will not occur
until the Utility files for new retail rates and the CPUC authorizes them.
During the transition period, the Utility is required to continue to use the
transition period accounting mechanisms, discussed above. This requires that
revenues from sales to the PX of Utility-owned generation and generation from
QFs and other providers in excess of costs be credited to the TCBA. In
addition, the TCBA balance includes a credit for the amount of PX revenues
from the Utility's sale of generation from the Diablo Canyon nuclear power
plant to the PX that exceed revenues from the fixed Incremental Cost Incentive
Price (ICIP). (During 2000, the ICIP is 3.43 cents per kWh.) After
taking into account the credit for the hydroelectric assets described
above, at September 30, 2000, the Utility's TCBA had a credit balance of
approximately $585 million. As mentioned above, the CPUC has issued a ruling
indicating that it would reconsider certain of these accounting mechanisms
noting that the CPUC has the authority to implement any necessary changes to
the electric restructuring accounting provisions and cost recovery consistent
with statutory requirements.
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 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 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 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.
As discussed above, on August 9, 2000, the Utility and a number of
interested parties filed an application with the CPUC requesting that the
CPUC approve a settlement agreement reached by these parties in the Utility's
proceeding to determine the market value of its hydroelectric generation
assets. In this settlement agreement, the Utility indicated that it would
transfer its hydroelectric generation assets, at a value of $2.8 billion, to
an affiliate (referred to herein as PG&E CalHydro) that would not be subject
to cost of service regulation by the CPUC.
PG&E CalHydro would hold and operate the assets, subject to a 40-year
revenue sharing agreement (RSA) between PG&E CalHydro and the Utility. Under
the RSA, PG&E CalHydro would be allowed to recover an authorized inflation-
indexed operations and maintenance allowance, certain other expenses
including an allowance for capital additions, and a return on capital
investment. The return on equity (ROE) initially would be set at 12.50
percent and would be subject to an indexed adjustment trigger. Under the
RSA, 90 percent of the after-tax earnings received in excess of the agreed-
upon costs (including the target ROE) would be returned to the Utility to be
used as a credit against current costs charged to the Utility's distribution
ratepayers. If market revenues were insufficient to recover the agreed-upon
costs of operating the hydroelectric facilities (including the target ROE)
over a multi-year period, 90 percent of the revenue shortfalls would be
charged to the Utility to be recovered from distribution customers.
The RSA would become effective on the date that the CPUC order approving the
settlement and the RSA becomes final and non-appealable, subject to
termination by either the Utility or PG&E CalHydro in certain circumstances.
The CPUC may accept the settlement or reject it, suggest changes to it, or
adopt a different valuation approach. In addition, the transfer of the assets
from the Utility to PG&E CalHydro will require the approval of the FERC.
At September 30, 2000, the book value of the Utility's net investment in
hydroelectric generation assets was approximately $700 million. The above
settlement, if approved, would result in a pre-tax charge of $2.1 billion. If
the value of the hydroelectric generation assets is determined by any method
other than a sale of the assets to an unrelated third party, 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. The CPUC is not likely to consider the Utility's proposed
settlement until next year, and it is uncertain at this time whether the
settlement will be approved, modified or rejected, or withdrawn.
Post-Transition Period
- ----------------------
The CPUC has established the Purchased Electric Commodity Account (PECA)
for the Utility to track energy costs after the rate freeze and transition
period end. In June 2000, the CPUC issued a decision in the second phase of
the Utility's post-transition period electric ratemaking proceeding. Among
other things, the CPUC determined that the PECA would reflect a pass-through
of energy costs, possibly subject to after-the-fact reasonableness reviews.
After the rate freeze ends, Diablo Canyon will be operated as a competitive
generator of electricity with revenues generated from prevailing market
rates. During the rate freeze, Diablo Canyon's operating costs have been
recovered through the incremental cost incentive price (ICIP) mechanism. 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.
As required by a prior CPUC decision on June 30, 2000, the Utility filed an
application with the CPUC requesting approval of its proposal for sharing
with ratepayers 50 percent of the post-rate freeze net benefits of operating
Diablo Canyon. The net benefit sharing methodology proposed in the Utility's
application would be effective at the end of the current electric rate freeze
for the Utility's customers and would continue for as long as the Utility
owned Diablo Canyon. Under the proposal, the Utility would share the net
benefits of operating Diablo Canyon based on the audited profits from
operations, determined consistent with the prior CPUC decisions. If Diablo
Canyon experiences losses, such losses would be accrued and netted against
profits in the calculation of the net benefits in subsequent periods (or
against profits in prior periods if subsequent profits are insufficient
to offset such losses). Any changes to the net sharing methodology must be
approved by the CPUC.
Future Competition
- ------------------
Opening California's electric generation to competition has raised certain
interest in introducing further competition in the electric industry. The
CPUC has opened a rulemaking proceeding to examine the various issues
associated with distributed generation. Distributed generation enables the
siting of electric generation technologies in close proximity to electric
demand, and raises issues about stranded costs (both within distribution and
transmission systems), interconnection charges, and cost allocation. The CPUC
staff has issued a report identifying options for possible CPUC consideration
regarding the additional unbundling of the electric distribution function and
evaluate the investor-owned utilities' role of default provider of
electricity.
It is too early to predict what may come of these matters. PG&E
Corporation is unable to predict when these issues will be addressed by the
CPUC or whether the results will have any impact on the Utility.
PG&E NATIONAL ENERGY GROUP
PG&E National Energy Group has been formed to pursue opportunities created
by the gradual restructuring of the energy industry across the nation. PG&E
National Energy Group integrates our national power generation, gas
transmission, and energy trading businesses. 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. 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 nine months ended September 30, 2000, the contract SOS
price paid to generators was $.38 per kWh for generation. On March 1, 1999,
Constellation Power Source, Inc. 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 September 30, 2000, these agreements provided for an
aggregate 470 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.
Currently, approximately 60 percent to 70 percent of the capacity is
dedicated to serving 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 continue to 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, PG&E National Energy Group signed a definitive
agreement providing for the sale 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 PG&E National Energy Group
includes $279 million in cash, subject to adjustments for working capital,
as well as the assumption by El Paso of liabilities associated with PG&E GT
Texas and debt having a book value of approximately $566 million.
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 fourth quarter 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
disposal has been accounted for as a discontinued operation and PG&E
Corporation's investment in PG&E ES was written down to its then estimated
net realizable value. In addition, PG&E Corporation provided a reserve for
anticipated losses through the anticipated date of sale. The total provision
for discontinued operations was $58 million, net of income taxes of $36
million. During the second quarter of 2000, PG&E National Energy Group
finalized the transactions related to the disposal of PGE ES for $20 million,
plus net working capital of approximately $65 million, for a total of $85
million. In addition, the sale of the Value-Added Services business and
various other assets was completed on July 21, 2000, for a total consideration
of $18 million. Both of these sales have working capital true-ups, which will
not be finalized until 2001. For the three and nine months ended September
30, 2000, an additional estimated loss of $19 million (or $0.05 per share),
net of income taxes of $13 million was recorded as actual and anticipated
losses in connection with the disposition. The PG&E ES business segment
generated net losses from operations of $34 million, net of income taxes of
$26 million for the nine-month period ended September 30, 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 during the transition period
because these rates are frozen. 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 Utility's pending
proceedings to determine the method for sharing the net benefits of operating
Diablo Canyon with ratepayers after the rate freeze and the value of its
hydroelectric generation assets and how such valuation will affect the
Utility's ability to recover its generation-related transaction costs are
discussed above.
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 net earnings for the
nine months ended September 30, 1999, would have been $115 million higher
than reported.
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 by the end of
2000.
The 2002 General Rate Case (GRC)
- --------------------------------
Also in the 1999 GRC final decision, the CPUC ordered the Utility to file a
2002 GRC. In July 2000, the CPUC issued a decision requiring the Utility to
file a Notice of Intent with the CPUC by May 1, 2001, a delay of nine months
compared to the procedural timetable in effect for the 1999 GRC. The CPUC
decision affirms that rates would still become effective on January 1, 2002,
although the CPUC decision may not be rendered until late 2002.
The 2001 Attrition Rate Adjustment (ARA)
- ----------------------------------------
In July 2000, the Utility filed an ARA application with the CPUC to
increase its 2001 electric distribution revenues by $189 million, effective
January 1, 2001, to reflect inflation and the growth in capital investments
necessary to serve customers. The Utility did not request an increase in gas
distribution revenues. The Utility has requested expedited treatment of the
application and has proposed a schedule to ensure that the 2001 ARA decision
is issued before January 1, 2001. The assigned commissioner has issued a
ruling that requires hearings on a number of issues and indicated that a final
decision would be issued no later than January 2002. However, that ruling
stated that the CPUC will consider an interim order that would allow the final
decision to be effective on an earlier date. The Utility intends to file a
request for an interim order granting the full attrition relief requested
subject to refund or adjustment when the final decision is issued.
The Year 2000 Cost of Capital Proceeding
- ----------------------------------------
In June 2000, the CPUC issued a final decision in the Utility's 2000 cost
of capital proceeding, adopting a return on common equity (ROE) of 11.22
percent on electric and gas distribution operations, retroactive to February
17, 2000, as compared to the Utility's former authorized ROE of 10.6
percent. The decision also affirmed the existing authorized Utility capital
structure of 46.2 percent long-term debt, 5.8 percent preferred stock, and
48.0 percent common equity.
The decision results in an authorized 9.12 percent overall rate of return
(ROR) on Utility electric and gas distribution rate base. The Utility's 2000
electric and gas revenues will increase by approximately $37 million and $12
million, respectively, for the period February 17, 2000, through December 31,
2000.
The Year 2001 Cost of Capital Proceeding
- ----------------------------------------
In May 2000, the Utility filed an application with the CPUC to establish
its authorized ROR for electric and gas distribution operations for 2001.
The application requests a ROE of 12.4 percent, and an overall 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 1.18 percent higher
than the 2000 ROE of 11.22 percent. If granted, the requested ROR would
increase electric distribution revenues by approximately $72 million and gas
distribution revenues by approximately $23 million. 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.
In the current year, the FERC has approved two settlements. In April 2000,
the FERC approved a settlement that permits the Utility to recover $264
million in electric transmission rates retroactively for the 10-month period
from May 31, 1999 to March 31, 2000. In September 2000, the FERC approved
another settlement that permits the Utility to recover $340 million annually
in electric transmission rates and made this retroactive to April 1, 2000.
In October 2000, the Utility filed a request to increase future revenues by
$57 million annually to $397 million in electric transmission rates. The
Utility does not expect a material impact on its financial position or
results of operations resulting from these matters.
The CPUC's Gas Strategy Investigation, Phase 2
- ----------------------------------------------
In January 1998, the CPUC opened a rulemaking proceeding to explore
alternative market structures in the natural gas industry in California. In
January 2000, the Utility and a broad-based coalition of shippers, consumer
groups, marketers, and others filed a settlement with the CPUC which
reaffirmed the basic structure of the Gas Accord and would continue the Gas
Accord through its original term of December 31, 2002. In May 2000, the CPUC
approved the uncontested settlement.
Performance-Based Ratemaking (PBR) Application
- ----------------------------------------------
In June 2000, the CPUC granted the Utility's request to withdraw its PBR
application filed in November 1998. The Utility had requested the withdrawal
in accordance with the 1999 General Rate Case decision issued in February
2000, which required a 2002 GRC before a PBR revenue/rate indexing mechanism
could be implemented. In closing the PBR proceeding, the CPUC ordered the
Utility to file a new PBR application by September 2000, for financial
rewards/penalties associated with utility performance in meeting prescribed
standards on measures such as electric reliability and customer service.
In September 2000, the Utility filed an application with the CPUC to
establish (1) performance standards and associated financial rewards and
penalties for electric and gas distribution service (2) a revenue-sharing
mechanism for new categories of non-tariffed products and services (NTP&S)
offered by the Utility and (3) ratemaking for proceeds from sales or transfers
of certain non-generation related land. The total maximum annual reward or
penalty is $54 million per year, consisting of $52 million for electric
distribution and $2 million for gas distribution. The revenue-sharing
mechanism proposes to share net positive after-tax revenues from new
categories of NTP&S equally between ratepayers and shareholders. Finally, the
Utility requests that the CPUC establish basic rules about the allocation of
gains and losses from the Utility's non-generation-related land sales.
RESULTS OF OPERATIONS
The table below presents for the three and nine months ended September 30,
2000 and 1999, certain items from our Condensed Consolidated Income Statement
detailed by Utility and PG&E National Energy Group operations of PG&E
Corporation. (In the Total column, the table shows the consolidated results
of operations for these groups.) The information for PG&E Corporation (the
Total column) includes the appropriate intercompany elimination. Following
this table we discuss our results of operations.
Utility PG&E National Energy Group
------- ---------------------------------------------
PG&E GT Elimi-
---------------- nations &
PG&EGen NW Texas PG&E ET Other (1) Total
------- ------- ------- ------- --------- --------
(in millions)
For the three months ended September 30, 2000
Operating revenues $ 2,523 $ 290 $ 64 $ 258 $ 4,777 $ (408) $ 7,504
Operating expenses 1,990 257 28 224 4,766 (390) 6,875
------- ------- ------- ------- ------- ------- ---------
Operating income 629
Other income, net 45
Interest expense, net 191
Income taxes 239
Income from continuing
operations 244
Net income $ 225
EBITDA (2) $ (446) $ 58 $ 46 $ 28 $ 13 $ (19) $ (320)
For the three months ended September 30, 1999
Operating revenues $ 2,587 $ 275 $ 56 $ 177 $ 3,490 $ (368) $ 6,217
Operating expenses 2,101 255 26 174 3,521 (376) 5,701
------- ------- ------- ------- ------- ------- -------
Operating income 516
Other income, net 20
Interest expense, net 190
Income taxes 149
Income from continuing
operations 197
Net income $ 185
EBITDA (2) $ 1,096 $ 43 $ 47 $ 17 $ (29) $ 10 $ 1,184
For the nine months ended September 30, 2000
Operating revenues $ 7,037 $ 883 $ 177 $ 707 $ 10,493 $ (1,147) $ 18,150
Operating expenses 5,382 763 77 657 10,468 (1,124) 16,223
------- ------ ------ ------ ------ ------ ------
Operating income 1,927
Other income, net 72
Interest expense, net 556
Income taxes 671
Income from continuing
operations 772
Net income $ 753
EBITDA (2) $ 1,006 $ 187 $ 131 $ 37 $ 32 $ (24) $ 1,369
For the nine months ended September 30, 1999
Operating revenues $ 6,905 $ 818 $ 166 $ 970 $8,145 $ (979) $ 16,025
Operating expenses 5,545 742 76 1,001 8,181 (977) 14,568
------ ------ ------ ------ ------ ------- -------
Operating income 1,457
Other income, net 81
Interest expense, net 583
Income taxes 395
Income from continuing
operations 560
Net income $ 538
EBITDA (2) $ 2,841 $ 157 $ 128 $ 22 $ (29) $ 1 $ 3,120
<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 third quarter of 2000 increased 21.6
percent to $225 million from $185 million in the prior year's third quarter.
Of the $40 million increase, PG&E National Energy Group accounted for $8
million of the increase and the Utility's third quarter net income available
for common stock accounted for $32 million of the increase.
Net income for the nine-month period ended September 30, 2000, increased
40.0 percent to $753 million from $538 million for the same period in 1999.
Of the $215 million increase, PG&E National Energy Group accounted for $58
million of the increase and the Utility's net income available for common
stock for the first nine months of 2000 accounted for $157 million of the
increase.
The 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. If the prior
year's quarterly periods had been restated for the general rate case outcome,
the rate order would have increased the 1999 third quarter Utility net
earnings by approximately $38 million ($0.11 per share) and increased 1999
year-to-date earnings by approximately $115 million ($0.32 per share).
- In the second quarter of 2000, the Utility received a final decision
from the CPUC increasing its authorized cost of capital from 10.6 percent to
11.22 percent, retroactive to February 2000, resulting in an approximate $7
million ($0.02 per share) and $18 million ($0.05 per share) increase in the
2000 third quarter and year-to-date earnings, respectively, as compared to
similar periods in 1999.
- PG&E Energy Trading's (PG&E ET) third quarter 2000 net income before
restructuring charges increased $22 million over 1999 third quarter results
due to across the board improvements in gas and power trading, asset
management, and structured transactions. This increase was offset by a $4
million after-tax ($.01 per share) charge associated with the restructuring
of PG&E National Energy Group. PG&E ET's net income for the first nine months
of 2000, net of restructuring charges of $13 million after-tax ($0.04 per
share), increased $33 million compared to the same period of 1999.
- At the end of 1999, PG&E Corporation also announced its plans to dispose
of PG&E GT Texas and these assets were written down to estimated fair value.
PG&E GT Texas has operated at a breakeven basis in 2000 and reported losses
of $7 million ($0.02 per share) and $33 million ($0.10 per share) for the
three and nine months ended September 30, 1999, respectively.
- 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, has 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 for the first nine months of 1999.
- At the end of 1999, PG&E Corporation announced its plans to dispose of
PG&E Energy Services (PG&E ES) and these assets were written down to net
realizable value. PG&E ES has operated at a breakeven basis in 2000 and
reported losses of $12 million ($0.03 per share) and $34 million ($0.09 per
share) for the three and nine months ended September 30, 1999, respectively.
Additionally, during the third quarter of 2000, the Company recorded an after-
tax charge of $19 million ($0.05 per share) to reflect the closing of
transactions to dispose of the retail energy services business and related
commodity portfolio.
Operating Revenues
- ------------------
Utility operating revenues decreased $64 million and increased $132 million
in the third quarter and first nine months of 2000, respectively, compared to
similar periods of the prior year. The decrease for the third quarter of
2000, as compared to the same period in 1999, is principally attributable to
the effect of higher wholesale power market prices and resulting credits
issued to direct access customers. These customers, principally large
industrial companies, procure electricity from independent generators under
long-term contracts and receive a credit on their utility bills at prevailing
market prices.
The increase in operating revenues for the nine-month period ended September
30, 2000, as compared to the same period in 1999, relates to higher gas and
electric sales to commercial and industrial customers due to their higher
usage. Additionally, increases in the price of gas have increased revenues.
PG&E National Energy Group operating revenues increased $1,351 million and
$1,993 million in the third quarter and first nine months of 2000,
respectively, compared to similar periods of 1999. PG&E National Energy
Group has focused its trading efforts on asset management, structured
transactions, and higher-margin trades, resulting in increased trading volume
principally in the Northeast. In addition, increases in the price of power
and gas in the second and third quarters resulted in increased revenues.
Operating Expenses
- ------------------
Utility operating expenses decreased $111 million and $163 million in the
three and nine month periods ended September 30, 2000, respectively, compared
to similar periods of the prior year.
The tables below summarize the changes in the Utility's operating expenses:
Three months ended
September 30, Increase Increase
2000 1999 (Decrease) (Decrease)
-------- -------- -------- --------
(in millions)
Utility operating expenses:
Cost of electric energy $ 2,056 $ 746 $ 1,310 175.6%
Deferred electric procurement costs (2,176) - (2,176) -
Cost of gas 178 118 60 50.8%
Operating and maintenance, net 730 615 115 18.7%
Depreciation, amortization and decommissioning 1,202 622 580 93.2%
-------- -------- -------- --------
Total $ 1,990 $ 2,101 $ (111) (5.3)%
======== ======== ======== ========
Nine months ended
September 30, Increase Increase
2000 1999 (Decrease) (Decrease)
-------- -------- -------- --------
(in millions)
Utility operating expenses:
Cost of electric energy $ 3,544 $ 1,681 $ 1,863 110.8%
Deferred electric procurement costs (2,789) - (2,789) -
Cost of gas 643 502 141 28.1%
Operating and maintenance, net 1,824 1,849 (25) (1.4)%
Depreciation, amortization and decommissioning 2,160 1,513 647 42.8%
-------- -------- -------- ---------
Total $ 5,382 $ 5,545 $ (163) (2.9)%
======== ======== ======== =========
The overall decrease in operating expenses is attributable to the deferral
of increased wholesale energy prices during the third quarter of 2000. To the
extent that current operating costs, including the cost of electric energy,
exceed frozen utility electric revenues, wholesale energy costs are deferred
in accordance with California's transition plan.
The increase in depreciation expense of $580 million and $647 million, for
the three and nine month period ended September 30, 2000, respectively, as
compared to the same periods in the prior year, is attributable to the
accelerated amortization arising from proceeds from sales to the PX being
applied to offset transition costs in accordance with California's transition
plan.
The increase in operating and maintenance expense reflects the impact in
2000 of an unscheduled 10-day outage at Diablo Canyon with no such outage in
the same period of the prior year. The cost of electric energy and the cost
of gas both increased for the quarter and year-to-date over comparable prior
year periods because of increases in the volume of gas purchased and increases
to the price of power and gas.
Operating expenses at PG&E National Energy Group increased $1,285 million
and $1,818 million in the third quarter and first nine months of 2000,
respectively, compared to the similar periods of the prior year. The increase
results from the increased trading volumes discussed above, increases in the
cost of power and gas, partially offset by reduced depreciation and
amortization expense at PG&E GT Texas reflective of the disposal of the PG&E
GT Texas assets.
EBITDA
- -------
PG&E Corporation's EBITDA has decreased $1,504 million and $1,751 million
to ($320) million and $1,369 million for the third quarter and first nine
months of 2000, respectively. The decreases are principally attributable to
the impact of higher fuel prices at the Utility during the third quarter of
2000. The Utility defers the increased fuel costs in excess of the generation
component in frozen rates through its regulatory balancing account mechanism
in accordance with California's transition plan.
Income Taxes
- ------------
The effective tax rate for the Corporation has increased to 46.5 percent in
the first nine months of 2000 compared to 41.4 percent in the prior year's
first nine months 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 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. 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. In addition, a material write-off of net generation-related
regulatory assets, including deferred electric procurement costs, or the
Utility's inability to continue to defer future electric procurement costs, as
discussed above, could necessitate a waiver of the CPUC's authorized capital
structure in order to permit PG&E Corporation or the Utility to continue to
pay 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 $1,210
million and $2,023 million during the nine months ended September 30, 2000 and
1999, respectively.
Utility:
Net cash provided by the Utility's operating activities totaled $1,297
million and $1,923 million during the nine months ended September 30, 2000 and
1999, respectively. High PX prices in the third quarter of 2000 have adversely
impacted the amount of cash generated by the Utility from operations during
these months. However, monthly payments to the ISO and PX are due 90 days
after the end of the month of service increasing the Utility's accounts payable
balance. The significant extent to which costs have exceeded revenues in
recent months and are expected to continue to exceed current revenues, has
caused the Utility to obtain additional sources of financing.
On October 19, 2000, the CPUC approved the Utility's request to increase its
current authorized amount of short-term debt by $1.4 billion, raising the
Utility's short-term debt authority to $3.1 billion. The additional $1.4
billion may only be used for the purpose of financing the purchase of wholesale
power for delivery to the Utility's retail customers. The Utility has
executed a credit agreement for an additional $1 billion in revolving credit
facilities to provide commercial paper backup to support its higher purchased
power costs and the associated increases in the TRA. The Utility is in the
process of completing the sale of $670 million of 364-day Floating Rate Notes
and $680 million of Senior Notes due on November 1, 2005 to meet financing
needs under existing authorities. Additionally, the Utility has filed a
request with the CPUC requesting authority to issue an additional $2 billion in
long-term debt instruments. The Utility's liquidity will depend in significant
part upon the extent to which regulatory bodies allow the Utility to recover in
rates the deferred energy procurement costs discussed above.
PG&E National Energy Group:
We have entered into tolling agreements with several counterparties giving
PG&E ET the rights to sell electricity generated by facilities owned and
operated by another party. Under such arrangements, PG&E ET supplies the
fuel to the power plant, and then sells the plant's output in the competitive
market. At September 30, 2000, the annual estimated committed payments under
such contracts range from approximately $1 million to $151 million,
resulting in total committed payments over the next 22 years of approximately
$2.5 billion.
Cash Flows from Financing Activities
- ------------------------------------
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.
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 short-
term liquidity needs. The facility expiring in 2000 may be extended annually
for additional one-year periods upon agreement with the lending institutions.
There was $587 million of commercial paper outstanding at September 30, 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 and is not supported by the credit facilities.
There were $200 million of ECNs outstanding at September 30, 2000. Also, at
September 30, 2000, PG&E Corporation has $819 million of short-term
investments.
During the nine-month period ended September 30, 2000, we issued $52 million
of common stock, primarily through the Dividend Reinvestment Plan and the stock
option plan component of the Long-Term Incentive Program. During the nine-
month period ended September 30, 2000, we paid dividends on our common stock of
$325 million.
During the nine-month period ended September 30, 1999, we repurchased $534
million of our common stock. The 1999 repurchases were executed through
accelerated share repurchase programs. Under the agreement, PG&E Corporation
purchased 16.6 million shares of its common stock from a counterparty and
entered into a forward contract with the counterparty. PG&E Corporation
retained the risk of increases and the benefit of decreases in the price of
the common shares purchased by the counterparty. PG&E Corporation had the
option to settle its obligations under the forward contract with either cash
or shares of its common stock. For the three- and nine-month periods ended
September 30, 1999, this agreement caused the none and $0.01 dilution,
respectively, reflected in PG&E Corporation's diluted earnings per share.
This dilution was eliminated when the associated forward contract was settled.
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 September 30, 2000,
through our wholly owned subsidiary, we repurchased 7.2 million shares, at a
cost of $159 million under this authorization.
Utility:
During the nine months ended September 30, 2000, the Utility paid dividends
on its common stock of $375 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 nine months ended September 30, 2000, totaled $291
million. Of this amount, $213 million related to the Utility's rate reduction
bonds maturing, and $78 million related to the maturities of various of the
Utility's medium-term notes and other debt. As discussed above, The Utility is
in the process of completing the sale of $1,350 million of Floating Rate and
Senior Notes. On October 18, 2000, it filed a request with the CPUC requesting
authority to issue an additional $2 billion in long-term debt. Although there
can be no assurance, the Utility believes it will be able to obtain additional
financing on acceptable terms and conditions.
The Utility maintains a $1 billion revolving credit facility, which expires
in 2002. The Utility may extend the facility annually for additional one-year
periods upon agreement with the banks. This facility is used to support the
Utility's commercial paper program and other liquidity requirements. The total
amount outstanding at September 30, 2000, backed by this facility, was $917
million in commercial paper. The next payments to the ISO and PX are due
October 31, 2000. In the third quarter the Utility requested and received
permission from the CPUC to increase its short-term borrowing authority by $1.4
billion to $3.1 billion. On October 18, 2000, it executed a credit agreement
for an additional $1 billion in revolving credit facilities to provide
commercial paper backup to support the higher purchased power costs experienced
since June 2000. The Utility also introduced a $200 million ECN program which
is not supported by the credit facilities. At September 30, 2000 there were no
amounts outstanding under this program. At September 30, 2000, the Utility
also had $242 million in short-term investments.
PG&E National Energy Group:
During the nine months ended September 30, 2000, PG&E National Energy Group
retired $385 million of long-term debt.
PG&E Gen maintains two $550 million revolving credit facilities to support
commercial paper programs, letters of credit and other short-term liquidity
requirements. One facility expires in August 2001 and the other expires in
2003. The total amount of commercial paper outstanding at September 30, 2000
was $1 billion, with $500 million classified as noncurrent in the Condensed
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 September 30, 2000,
there was 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 2001, but can be extended for successive 364-day
periods. At September 30, 2000, PG&E GT NW had an outstanding commercial paper
balance of $29 million, which is classified as noncurrent in the Condensed
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 September 30, 2000, PG&E GTT had
$215 million of outstanding short-term bank borrowings related to these credit
facilities. These lines are cancelable upon demand and bear interest at each
respective bank's quoted money market rate. The borrowings are unsecured and
unrestricted as to use.
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 nine months ended
September 30, 2000, was $874 million.
PG&E National Energy Group:
Four natural gas-fueled combined-cycle power plants are currently under
construction which when completed will be owned or leased by PG&E National
Energy Group. 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 expected
to begin commercial service in the last quarter of 2000. Lake Road Generating
Plant (Lake Road), an approximately 790-MW power plant located in Connecticut,
is expected to begin commercial service in 2001. La Paloma Generating Plant
(La Paloma), an approximately 1,050-MW power plant located in California, is
expected to begin commercial service in 2002. On September 28, 2000, PG&E
National Energy Group purchased the Attala Power Project. Attala is a 500 MW
gas-fired combined cycle project, which is approximately 50 percent complete,
located in Mississippi and is expected to begin commercial service by summer
2001. During the second quarter critical environmental permits were obtained
for the Athens Generating Plant, an approximately 1,080-MW power plant located
in New York, and the approximately 1,040-MW Harquahala generating project
located in Arizona. Both plants are expected to begin commercial service in
2003.
Lake Road and La Paloma are being financed through synthetic leases with a
third-party owner. PG&E National Energy Group will operate the plants under
operating leases. The estimated cost to construct these plants is
approximately $1.4 billion.
PG&E National Energy Group 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 began commercial operation
in October 2000.
In addition to the above projects under construction, PG&E National Energy
Group has an additional 9,000 to 10,000 MW in development for commercial
operation in the next five years. The expected commercial operation dates of
the projects discussed above and the completion of future projects is
subject to many factors, including but not limited to various regulatory and
environmental approvals, adequate financing on satisfactory terms,
competitive conditions including the expansion and retirement plans of
others, market prices for electricity, future fuel prices, delays by third
party contractors, and the availability of required equipment.
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. (See Note 6 of Notes to
Condensed Consolidated Financial Statement for further discussion of these
matters.)
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 September 30, 2000, was
$2.8 million for trading activities and $12.2 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.
PG&E Corporation expects to adopt Statement of Financial Accounting
Standards (SFAS) No. 133, as amended by SFAS No. 138, effective 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 6 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
-----------------
For a description of material legal proceedings, see Note 6 of the PG&E
Corporation and Pacific Gas and Electric Company Notes to Condensed
Consolidated Financial Statements under Part I, Item 1 above, as well as the
Annual Report on Form 10-K filed by PG&E Corporation and Pacific Gas and
Electric Company for the year ended December 31. 1999, and the Quarterly
Report on Form 10-Q filed by PG&E Corporation and Pacific Gas and Electric
Company for the quarter ended March 31, 2000.
Item 5. Other Information
-----------------
Ratio of Earnings to Fixed Charges and Ratio of Earnings to
Combined Fixed Charges and Preferred Stock Dividends
Pacific Gas and Electric Company's earnings to fixed charges ratio for the
nine months ended September 30, 2000, was 3.72. Pacific Gas and Electric
Company's earnings to combined fixed charges and preferred stock dividends
ratio for the nine months ended September 30, 2000, was 3.53. 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 Bylaws of PG&E Corporation, dated as of August 22, 2000
Exhibit 3.2 Bylaws of Pacific Gas and Electric Company, dated as of
August 22, 2000
Exhibit 11 Computation of Earnings Per Common Share
Exhibit 12.1 Computation of Ratios of Earnings to Fixed
Charges for Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined
Fixed Charges and Preferred Stock Dividends for
Pacific Gas and Electric Company
Exhibit 27.1 Financial Data Schedule for the quarter ended
September 30, 2000, for PG&E Corporation
Exhibit 27.2 Financial Data Schedule for the quarter ended
September 30, 2000, for Pacific Gas and Electric
Company
(b) The following Current Reports on Form 8-K were filed during the third
quarter of 2000 and through the date hereof (2):
1. August 9, 2000
Item 5. Other Events
Pacific Gas and Electric Company's
Hydroelectric Generation Assets
2. September 14, 2000
Item 5. Other Events
Pacific Gas and Electric Company's
Attrition Rate Adjustment Application
3. October 25, 2000
Item 5. Other Events
Third Quarter 2000 Consolidated Earnings,
Pacific Gas and Electric Company's
Wholesale Power Purchase Costs, and Other Matters
- ---------------
(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).
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: October 31, 2000
Exhibit Index
Exhibit No. Description of Exhibit
3.1 Bylaws of PG&E Corporation, dated as of August 22, 2000
3.2 Bylaws of Pacific Gas and Electric Company, dated as of
August 22, 2000
11 Computation of Earnings Per Common Share
12.1 Computation of Ratio of Earnings to Fixed Charges for
Pacific Gas and Electric Company
12.2 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas and Electric
Company
27.1 Financial Data Schedule for the quarter ended
September 30, 2000 for PG&E Corporation
27.2 Financial Data Schedule for the quarter ended
September 30, 2000 for Pacific Gas and Electric Company
26