SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
FORM 10-Q/A
Amendment No. 1 to
(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, 2001
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to __________
State or IRS
Exact Name of other Employer
Commission Registrant Jurisdiction Identifica
File as specified of tion
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 latest practicable date.
Common Stock Outstanding, October 31, 2001:
PG&E Corporation 387,257,572 shares
Pacific Gas and Electric Company Wholly-owned by PG&E Corporation
1
INTRODUCTORY NOTE
PG&E Corporation has previously disclosed that its subsidiary, PG&E National
Energy Group, Inc (PG&E NEG), has used "synthetic leases" in connection with
some of its power plant projects and turbine acquisition commitments. Subsequent
to the issuance of PG&E Corporation's 1999 and 2000 consolidated financial
statements, management determined that the assets and liabilities associated
with these leases should have been consolidated. This Amendment No. 1 to PG&E
Corporation's and Pacific Gas and Electric Company's joint Quarterly Report on
Form 10-Q/A for the quarter ended September 30, 2001, contains revised
Consolidated Financial Statements for PG&E Corporation for the quarters ended
September 30, 2001 and 2000. To reflect the revisions, this Amendment No. 1
hereby amends Part I. Financial Information of the original filing. Although the
full text of the amended Form 10-Q is contained herein, this Amendment No. 1
does not update Part II nor does this Amendment No. 1 update any other
disclosures to reflect developments since the original date of filing. The
exhibits that were filed with the original filing have not been re-filed with
this amendment but instead have been incorporated by reference to the original
filing.
2
PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY,
Form 10-Q/A
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2001
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION PAGE
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
REVISED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS 4
REVISED CONDENSED CONSOLIDATED BALANCE SHEETS 5
REVISED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS 7
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS 8
CONDENSED CONSOLIDATED BALANCE SHEETS 9
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS 11
NOTE 1: GENERAL 12
NOTE 2: THE CALIFORNIA ENERGY CRISIS 15
NOTE 3: VOLUNTARY PETITION FOR RELIEF UNDER CHAPTER 11
AND PLAN OF REORGANIZATION 21
NOTE 4: PRICE RISK MANAGEMENT 25
NOTE 5: SHORT-TERM BORROWINGS AND CREDIT FACILITIES 26
NOTE 6: LONG-TERM DEBT 27
NOTE 7: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING SOLELY
UTILITY SUBORDINATED DEBENTURES 28
NOTE 8: COMMITMENTS & CONTINGENCIES 29
NOTE 9: SEGMENT INFORMATION 34
NOTE 10: REVISIONS FOOTNOTE 36
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS 37
LIQUIDITY AND FINANCIAL RESOURCES 39
STATEMENT OF CASH FLOWS 44
RESULTS OF OPERATIONS 47
REGULATORY MATTERS 56
ENVIRONMENTAL MATTERS 61
PRICE RISK MANAGEMENT ACTIVITIES 63
LEGAL MATTERS 67
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 68
PART II OTHER INFORMATION 69
ITEM 1. LEGAL PROCEEDINGS 69
ITEM 3. DEFAULTS UPON SENIOR SECURITIES 74
ITEM 5. OTHER INFORMATION 76
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 76
SIGNATURE 79
3
PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)
Three months ended Nine months ended
September 30, September 30,
-------------------- --------------------
2001 2000 2001 2000
-------- -------- -------- --------
As revised, see Note 10
-----------------------
Operating Revenues
Utility $ 2,937 $ 2,523 $ 7,808 $ 7,037
Energy commodities and services 3,361 4,979 10,173 11,104
-------- -------- -------- --------
Total operating revenues 6,298 7,502 17,981 18,141
-------- -------- -------- --------
Operating Expenses
Cost of energy for utility 697 2,234 3,997 4,187
Deferred electric procurement costs - (2,176) - (2,789)
Cost of energy commodities and services 3,041 4,618 9,215 10,137
Operating and maintenance 713 958 2,293 2,411
Depreciation, amortization and decommissioning 270 1,239 784 2,268
Reorganization professional fees and expenses 25 - 33 -
-------- -------- -------- --------
Total operating expenses 4,746 6,873 16,322 16,214
-------- -------- -------- --------
Operating Income 1,552 629 1,659 1,927
Reorganization interest income 32 - 64 -
Interest income 29 59 106 109
Interest expense (317) (191) (876) (556)
Other income (expense), net (38) (14) (43) (37)
-------- -------- -------- --------
Income Before Income Taxes 1,258 483 910 1,443
Income tax provision 487 239 340 671
-------- -------- -------- --------
Income From Continuing Operations 771 244 570 772
Discontinued Operations
Loss on disposal of PG&E Energy Services (net of
applicable income taxes of $13 million) - (19) - (19)
-------- -------- -------- --------
Net Income $ 771 $ 225 $ 570 $ 753
======== ======== ======== ========
Weighted average common shares outstanding 363 362 363 361
-------- -------- -------- --------
Earnings (Loss) Per Common Share, Basic
Income from continuing operations $ 2.12 $ 0.67 $ 1.57 $ 2.14
Discontinued operations - (0.05) - (0.05)
-------- -------- -------- --------
Net Earnings $ 2.12 $ 0.62 $ 1.57 $ 2.09
======== ======== ======== ========
Earnings (Loss) Per Common Share, Diluted
Income from continuing operations $ 2.12 $ 0.67 $ 1.57 $ 2.12
Discontinued operations - (0.05) - (0.05)
-------- -------- -------- --------
Net Earnings $ 2.12 $ 0.62 $ 1.57 $ 2.07
======== ======== ======== ========
Dividends Declared Per Common Share $ - $ 0.30 $ - $ 0.90
======== ======== ======== ========
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
4
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
Balance at
-------------------------------
September 30, December 31,
2001 2000
------------- ------------
As revised, see Note 10
-----------------------
ASSETS
Current Assets
Cash and cash equivalents $ 1,020 $ 925
Short-term investments 4,609 1,634
Accounts receivable:
Customers (net of allowance for doubtful accounts of
$93 million and $71 million, respectively) 3,046 4,340
Regulatory balancing accounts 88 222
Price risk management 152 2,039
Inventories 539 392
Income taxes receivable - 1,241
Prepaid expenses and other 240 406
-------- --------
Total current assets 9,694 11,199
-------- --------
Property, Plant, and Equipment
Utility 24,617 23,872
Non-utility:
Electric generation 2,748 2,008
Gas transmission 1,584 1,542
Construction work in progress 2,054 1,605
Other 129 147
-------- --------
Total property, plant, and equipment (at original cost) 31,132 29,174
Accumulated depreciation and decommissioning (12,520) (11,878)
-------- --------
Net property, plant, and equipment 18,612 17,296
-------- --------
Other Noncurrent Assets
Regulatory assets 1,929 1,773
Nuclear decommissioning funds 1,324 1,328
Price risk management 52 2,026
Other 3,181 2,530
-------- --------
Total other noncurrent assets 6,486 7,657
-------- --------
TOTAL ASSETS $ 34,792 $ 36,152
======== ========
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statment.
5
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
----------------------------
September 30, December 31,
2001 2000
---------- ------------
As revised, see Note 10
-----------------------
LIABILITIES AND EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Short-term borrowings $ 319 $ 4,530
Long-term debt, classified as current 48 2,391
Current portion of rate reduction bonds 290 290
Accounts payable:
Trade creditors 1,226 5,896
Regulatory balancing accounts 293 196
Other 519 459
Price risk management 52 1,999
Other 1,560 1,570
--------- ----------
Total current liabilities 4,307 17,331
--------- ----------
Noncurrent Liabilities
Long-term debt 7,649 5,550
Rate reduction bonds 1,527 1,740
Deferred income taxes 1,865 1,656
Deferred tax credits 163 192
Price risk management 33 1,867
Other 3,754 3,864
--------- ----------
Total noncurrent liabilities 14,991 14,869
--------- ----------
Liabilities Subject to Compromise
Financing debt 5,828 -
Trade creditors 5,485 -
--------- ----------
Total liabilities subject to compromise 11,313 -
--------- ----------
Preferred Stock of Subsidiaries 480 480
Utility Obligated Mandatorily Redeemable Preferred Securities
of Trust Holding Solely Utility Subordinated Debentures - 300
Common Stockholders' Equity
Common stock, no par value, authorized 800,000,000 shares,
issued 387,173,251 and 387,193,727 shares, respectively 5,971 5,971
Common stock held by subsidiary, at cost, 23,815,500 shares (690) (690)
Accumulated deficit (1,533) (2,105)
Accumulated other comprehensive loss (47) (4)
--------- ----------
Total common stockholders' equity 3,701 3,172
--------- ----------
Commitments and Contingencies (Notes 1, 2, 3, and 8) - -
--------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 34,792 $ 36,152
========= ==========
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
6
PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Nine months ended
September 30,
--------------------
2001 2000
-------- --------
As revised, see Note 10
-----------------------
Cash Flows From Operating Activities
Net income $ 570 $ 753
Adjustments to reconcile net income to
net cash provided by operating activities:
Loss on disposal of businesses - 19
Deferred electric procurement costs - (2,789)
Depreciation, amortization, and decommissioning 784 2,268
Deferred income taxes and tax credits, net 180 545
Price risk management assets and liabilities, net 37 (98)
Other deferred charges and non-current liabilities (604) 861
Net effect of changes in operating assets and liabilities:
Short-term investments (2,975) (632)
Accounts receivable 1,294 (813)
Inventories (147) 123
Accounts payable 875 1,342
Accrued taxes 1,241 (506)
Regulatory balancing accounts payable 231 (360)
Other working capital 158 514
Other, net 155 30
-------- -------
Net cash provided by operating activities 1,799 1,257
-------- -------
Cash Flows From Investing Activities
Capital expenditures (1,818) (1,691)
Net proceeds from sales of businesses - 103
Other, net (235) (426)
-------- -------
Net cash used by investing activities (2,053) (2,014)
-------- -------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities (1,159) 894
Long-term debt issued 2,580 615
Long-term debt matured, redeemed, or repurchased (963) (432)
Common stock issued - 52
Dividends paid (109) (325)
-------- -------
Net cash provided by financing activities 349 804
-------- -------
Net change in cash and cash equivalents 95 47
Cash and cash equivalents at January 1 925 282
-------- -------
Cash and cash equivalents at September 30 $ 1,020 $ 329
======== =======
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amount capitalized) $ 421 $ 487
Income taxes paid (refunded) - net (1,241) 23
Transfer of liabilities and other payables subject to
compromise from operating payables and liabilities 11,313
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
7
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
Three months ended Nine months ended
September 30, September 30,
----------------------- --------------------
2001 2000 2001 2000
-------- -------- -------- -------
Operating Revenues
Electric $ 2,509 $ 1,999 $ 5,265 $ 5,401
Gas 428 524 2,543 1,636
------- ------- ------- -------
Total operating revenues 2,937 2,523 7,808 7,037
------- ------- ------- -------
Operating Expenses
Cost of electric energy 434 2,056 2,389 3,544
Deferred electric procurement costs - (2,176) - (2,789)
Cost of gas 263 178 1,608 643
Operating and maintenance 563 730 1,771 1,824
Depreciation, amortization, and decommissioning 224 1,202 663 2,160
Reorganization professional fees and expenses 25 - 33 -
------- ------- ------- -------
Total operating expenses 1,509 1,990 6,464 5,382
------- ------- ------- -------
Operating Income 1,428 533 1,344 1,655
Reorganization interest income 32 - 64 -
Interest income 7 31 31 49
Interest expense (contractual interest of $241 million
and $694 million for the three and nine months
ended September 30, 2001, respectively) (245) (150) (703) (435)
Other income (expense), net (6) (1) (12) (2)
------- ------- ------- -------
Income Before Income Taxes 1,216 413 724 1,267
Income tax provision 472 196 272 594
------- ------- ------- -------
Net Income 744 217 452 673
Preferred dividend requirement 7 6 19 18
------- ------- ------- -------
Income Available for Common Stock $ 737 $ 211 $ 433 $ 655
======= ======= ======= =======
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
8
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions)
Balance at
------------------------------
September 30, December 31,
2001 2000
-------------- -------------
ASSETS
Current Assets
Cash and cash equivalents $ 151 $ 111
Short-term investments 4,336 1,283
Accounts receivable:
Customers (net of allowance for doubtful accounts of
$51 million and $52 million, respectively) 1,676 1,711
Related parties 17 6
Regulatory balancing accounts 88 222
Inventories:
Gas stored underground and fuel oil 292 146
Materials and supplies 130 134
Income taxes receivable - 1,120
Prepaid expenses and other 85 45
--------- ---------
Total current assets 6,775 4,778
--------- ---------
Property, Plant, and Equipment
Electric 16,998 16,335
Gas 7,619 7,537
Construction work in progress 247 249
--------- ---------
Total property, plant, and equipment (at original cost) 24,864 24,121
Accumulated depreciation and decommissioning (11,656) (11,120)
--------- ---------
Net property, plant, and equipment 13,208 13,001
--------- ---------
Other Noncurrent Assets
Regulatory assets 1,901 1,716
Nuclear decommissioning funds 1,324 1,328
Other 1,582 1,165
--------- ---------
Total noncurrent assets 4,807 4,209
--------- ---------
TOTAL ASSETS $ 24,790 $ 21,988
========= =========
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
9
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
------------------------------
September 30, December 31,
2001 2000
------------- -------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Short-term borrowings $ - $ 3,079
Long-term debt, classified as current - 2,374
Current portion of rate reduction bonds 290 290
Accounts payable:
Trade creditors 194 3,688
Related parties 31 138
Regulatory balancing accounts 293 196
Other 276 363
Income taxes payable 359 -
Deferred income taxes 89 172
Other 615 670
------------ ------------
Total current liabilities 2,147 10,970
------------ ------------
Noncurrent Liabilities
Long-term debt 3,431 3,342
Rate reduction bonds 1,527 1,740
Deferred income taxes 1,168 929
Deferred tax credits 163 192
Other 2,884 2,968
------------ ------------
Total noncurrent liabilities 9,173 9,171
------------ ------------
Liabilities Subject to Compromise
Financing debt 5,828 -
Trade creditors 5,664 -
------------ ------------
Total liabilities subject to compromise 11,492 -
------------ ------------
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,
7.9%, 12,000,000 shares, due 2025 - 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 149 149
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 shares (475) (475)
Additional paid in capital 1,964 1,964
Accumulated deficit (1,546) (1,979)
Accumulated other comprehensive loss (2) -
------------ ------------
Total stockholders' equity 1,841 1,410
------------ ------------
Commitments and Contingencies (Notes 1, 2, 3, and 8) - -
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 24,790 $ 21,988
============ ============
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
10
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Nine months ended
September 30,
-------------------------
2001 2000
---------- -----------
Cash Flows From Operating Activities
Net income $ 452 $ 673
Adjustments to reconcile net income to
net cash provided by operating activities:
Deferred electric procurement costs - (2,789)
Depreciation, amortization, and decommissioning 663 2,160
Deferred income taxes and tax credits, net 127 540
Other deferred charges and non-current liabilities (658) 640
Net effect of changes in operating assets and liabilities:
Short-term investments (3,053) (221)
Accounts receivable 493 (117)
Income tax receivable 1,120 (295)
Inventories (142) 11
Accounts payable 1,003 1,093
Accrued taxes 359 (118)
Regulatory balancing accounts 231 (360)
Other working capital 663 100
Other, net 21 (20)
-------- -----------
Net cash provided by operating activities 1,279 1,297
-------- -----------
Cash Flows from Investing Activities
Capital expenditures (889) (874)
Other, net 3 38
-------- -----------
Net cash used by investing activities (886) (836)
-------- -----------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities (28) 468
Long-term debt matured, redeemed, or repurchased (325) (291)
Common stock repurchased - (275)
Dividends paid - (375)
-------- -----------
Net cash used by financing activities (353) (473)
-------- -----------
Net change in cash and cash equivalents 40 (12)
Cash and cash equivalents at January 1 111 80
-------- -----------
Cash and cash equivalents at September 30 $ 151 $ 68
======== ===========
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amount capitalized) $ 300 $ 295
Income taxes paid (refunded) - net (1,120) -
Transfer of liabilities and other payables subject to
compromise from operating payables and liabilities 11,492 -
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
11
PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Note 1: GENERAL
Basis of Presentation
PG&E Corporation was incorporated in California in 1995 and became the holding
company of Pacific Gas and Electric Company, a debtor-in-possession, (the
Utility) and its subsidiaries on January 1, 1997. The Utility, incorporated in
California in 1905, is the predecessor of PG&E Corporation. As discussed further
in Note 3, on April 6, 2001, the Utility filed a voluntary petition for relief
under Chapter 11 of the United States Bankruptcy Code (Bankruptcy Code) in the
United States Bankruptcy Court for the Northern District of California
(Bankruptcy Court). Under Chapter 11, the Utility retains control of its assets
and is authorized to operate its business as a debtor-in-possession while being
subject to the jurisdiction of the Bankruptcy Court. On September 20, 2001, the
Utility and PG&E Corporation jointly filed with the Bankruptcy Court a proposed
plan of reorganization (the Plan) of the Utility under Chapter 11 of the
Bankruptcy Code and their proposed disclosure statement describing the Plan.
This Quarterly Report on Form 10-Q/A is a combined report of PG&E Corporation
and the Utility. Therefore, the Notes to the unaudited Condensed Consolidated
Financial Statements apply to both PG&E Corporation and the Utility. PG&E
Corporation's unaudited Condensed Consolidated Financial Statements include the
accounts of PG&E Corporation, the Utility, and PG&E Corporation's wholly owned
and controlled subsidiaries. The Utility's unaudited Condensed Consolidated
Financial Statements include its accounts as well as those of its wholly owned
and controlled subsidiaries.
PG&E Corporation and the Utility believe that the accompanying unaudited
Condensed Consolidated Financial 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/A. All significant intercompany transactions have been eliminated from
the unaudited Condensed Consolidated Financial Statements.
Certain amounts in the prior year's unaudited Condensed Consolidated Financial
Statements have been reclassified to conform to the 2001 presentation. Results
of operations for interim periods are not necessarily indicative of results to
be expected for a full year.
This quarterly report should be read in conjunction with PG&E Corporation's and
the Utility's Consolidated Financial Statements and Notes to Consolidated
Financial Statements incorporated by reference in their combined 2000 Annual
Report on Form 10-K/A, and PG&E Corporation's and the Utility's other reports
filed with the Securities and Exchange Commission (SEC) since their 2000 Form
10-K/A was filed.
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.
12
Accounting for Price Risk Management Activities
Effective January 1, 2001, PG&E Corporation and the Utility adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for
Certain Derivative Instruments and Certain Hedging Activities." The Statement,
as amended, required PG&E Corporation and the Utility to recognize all
derivatives, as defined in the Statement, on the balance sheet at fair value.
PG&E Corporation's transition adjustment to implement this new Statement on
January 1, 2001, resulted in a non-material decrease to earnings and an increase
of $243 million to accumulated other comprehensive loss. The Utility's
transition adjustment to implement this new Statement resulted in a non-material
loss charged to earnings and a $90 million addition to accumulated other
comprehensive loss.
Derivatives are classified as price risk management assets or price risk
management liabilities on the balance sheet. Derivatives, or any portion
thereof, that are not effective hedges are adjusted to fair value through
income. For derivatives that are effective hedges, depending on the nature of
the hedge, changes in the fair value are either offset by changes in the fair
value of the hedged assets or liabilities through earnings or recognized in
accumulated other comprehensive income (loss) until the hedged item is
recognized in earnings. Net gains or losses recognized for the three- and
nine-month periods ended September 30, 2001 were included in various lines on
the Condensed Consolidated Statements of Operations including energy commodities
and services revenue, cost of energy commodities and services, interest income
or interest expense, and other income (expense), net.
PG&E Corporation has derivative commodity contracts for the physical delivery of
purchase and sale quantities transacted in the normal course of business. In
June 2001, the Financial Accounting Standards Board (FASB) approved an
interpretation issued by the Derivatives Implementation Group (DIG) that changed
the definition of normal purchases and sales for certain power contracts. PG&E
Corporation must implement this interpretation on January 1, 2002, and is
currently assessing the impact of these new rules. The FASB has also approved
another DIG interpretation that disallows normal purchases and sales treatment
for commodity contracts (other than power contracts) that contain volumetric
variability or optionality. Certain of PG&E Corporation's derivative commodity
contracts may no longer be exempt from the requirements of the Statement. PG&E
Corporation is evaluating the impact of this implementation guidance on its
financial statements, and will implement this guidance, as appropriate, by the
implementation deadline of April 1, 2002.
As of September 30, 2001, the maximum length of time over which PG&E Corporation
has hedged its exposure to the variability in future cash flows associated with
commodity price risk is through December 2005.
The Utility is party to various electric and gas bilateral contracts, some of
which were terminated in the first six months of 2001 (see Note 2). The value of
certain financial gas contracts terminated during the first six months of the
year was being amortized out of accumulated other comprehensive income (loss)
over the life of the related physical contracts previously being hedged, in
accordance with the provisions of SFAS No. 133. Through the second quarter of
2001, the Utility had amortized $20 million of losses associated with these
contracts. Those losses were partially offset through the second quarter of 2001
by gains from the hedged transactions. In the third quarter of 2001, a $66
million (after-tax) loss associated with the terminated contracts included
primarily in accumulated other comprehensive loss was recognized in earnings.
The loss was recognized in earnings due to changes in market conditions that
made
13
it unlikely that this loss would be offset when the related physical contracts
are recognized in earnings. SFAS No. 133 requires an entity to immediately
reclassify into earnings amounts in accumulated other comprehensive income
(loss) that are not expected to be recovered when the hedged transactions are
recognized in earnings in future periods.
Earnings Per Share
Basic earnings per share is computed by dividing net income by the weighted
average number of common shares outstanding during the period. Diluted earnings
per share is computed by dividing net income by the weighted average number of
common shares outstanding plus the assumed issuance of common shares for all
potentially dilutive securities.
The following is a reconciliation of PG&E Corporation's net income and weighted
average common shares outstanding for calculating basic and diluted net income
per share.
Three months ended Nine months ended
September 30, September 30,
----------------- ---------------------
2001 2000 2001 2000
------- ------ ------- -------
(in millions)
Income from continuing operations $ 771 $ 244 $ 570 $ 772
Discontinued operations - (19) - (19)
------- ------ ------- -------
Net income $ 771 $ 225 $ 570 $ 753
======= ====== ======= =======
Weighted average common shares outstanding 363 362 363 361
Add: Outstanding options reduced by the
number of shares that could be repurchased with
the proceeds from such purchase 1 3 - 2
------- ------ ------- -------
Shares outstanding for diluted calculations 364 365 363 363
======= ====== ======= =======
Earnings (Loss) Per Common Share, Basic
Income from continuing operations $ 2.12 $ 0.67 $ 1.57 $ 2.14
Discontinued operations - (0.05) - (0.05)
------- ------ ------- -------
Net earnings 2.12 0.62 1.57 2.09
======= ====== ======= =======
Earnings (Loss) Per Common Share, Diluted
Income from continuing operations 2.12 0.67 1.57 2.12
Discontinued operations - (0.05) - (0.05)
------- ------ ------- -------
Net earnings $ 2.12 $ 0.62 $ 1.57 $ 2.07
======= ====== ======= =======
Accumulated Other Comprehensive Income (Loss)
The objective of PG&E Corporation's and the Utility's accumulated other
comprehensive income (loss) is to report a measure for all changes in equity of
an enterprise that result from transactions and other economic events of the
period other than transactions with shareholders. PG&E Corporation's and the
Utility's accumulated other comprehensive income (loss) consists principally of
changes in the market value of certain financial hedges with the implementation
of SFAS No. 133 on January 1, 2001, as well as foreign currency translation
adjustments.
New Accounting Pronouncements
In June 2001, the FASB issued SFAS No. 141, "Business Combinations." This
14
Statement, which applies to all business combinations accounted for under the
purchase method completed after June 30, 2001, prohibits the use of
pooling-of-interests method of accounting for business combinations and provides
a new definition of intangible assets. PG&E Corporation and the Utility do not
expect that implementation of this Statement will have a significant impact on
their financial statements.
Also, in June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." This Statement eliminates the amortization of goodwill, and requires
that goodwill be reviewed at least annually for impairment. This Statement also
requires that the useful lives of previously recognized intangible assets be
reassessed and the remaining amortization periods be adjusted accordingly. This
Statement is effective for fiscal years beginning after December 15, 2001, and
affects all goodwill and other intangible assets recognized on a company's
statement of financial position at that date, regardless of when the assets were
initially recognized. The Utility does not expect that implementation of this
Statement will have a significant impact on its financial statement. PG&E
Corporation has not yet determined the effects of this Statement on its
financial statements.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This Statement is effective for fiscal years beginning after June
15, 2002. SFAS No. 143 provides accounting requirements for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. Under the Statement, the asset retirement obligation is
recorded at fair value in the period in which it is incurred by increasing the
carrying amount of the related long-lived asset. The liability is accreted to
its present value in each subsequent period and the capitalized cost is
depreciated over the useful life of the related assets. PG&E Corporation and the
Utility have not yet determined the effects of this Statement on their financial
statements.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets", which addresses financial accounting and
reporting for the impairment or disposal of long-lived assets. SFAS No. 144
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of", but retains the fundamental provisions
for recognizing and measuring impairment of long-lived assets to be held and
used or disposed of by sale. The Statement also supersedes the accounting and
reporting provisions for the disposal of a segment of a business, and eliminates
the exception to consolidation for a subsidiary for which control is likely to
be temporary. SFAS No. 144 eliminates the conflict between accounting models for
treating the disposition of long-lived assets that existed between SFAS No. 121
and the guidance for a segment of a business accounted for as a discontinued
operation by adopting the methodology established in SFAS No. 121, and also
resolves implementation issues related to SFAS No. 121. This Statement is
effective for fiscal years beginning after December 15, 2001. PG&E Corporation
and the Utility have not yet determined the effects of this Statement on their
financial statements.
NOTE 2: THE CALIFORNIA ENERGY CRISIS
Transition Period and Rate Freeze
In 1998, California implemented electric industry restructuring and established
a market framework for electric generation in which generators and other power
providers were permitted to charge market-based prices for wholesale power. The
restructuring of the electric industry was mandated by the California
Legislature
15
in Assembly Bill (AB) 1890. The electric industry restructuring law established
a transition period, mandated a rate freeze, and included a plan for recovery of
generation-related costs that were expected to be uneconomic under the new
market (transition costs). The California Public Utilities Commission (CPUC)
required the California investor-owned utilities to file a plan to voluntarily
divest at least 50% of their fossil-fueled generation facilities and discouraged
utility operation of their remaining facilities by reducing the return on such
assets. The new market framework called for the creation of the Power Exchange
(PX) and the Independent System Operator (ISO). Before it ceased operating in
March 2001, the PX established market-clearing prices for electricity. The ISO's
role was to schedule delivery of electricity for all market participants and
operate certain markets for electricity. Until December 15, 2000, the Utility
was required to sell all of its owned and contracted generation to, and purchase
all electricity for its retail customers from, the PX. Customers were given the
choice of continuing to buy electricity from the Utility or buying electricity
from independent power generators or retail electricity suppliers. Most of the
Utility's customers continued to buy electricity through the Utility.
The rate freeze established by AB 1890 was scheduled to end on the earlier of
March 31, 2002, or the date the Utility recovers all of its transition costs as
determined by the CPUC.
Beginning in June 2000, wholesale spot prices for electricity sold through the
PX and ISO began to escalate. While forward and spot prices moderated somewhat
in September and October 2000, such prices skyrocketed in November and December
2000 to levels substantially higher than during the summer months. The average
price of electricity purchased by the Utility for the benefit of its customers
was $0.182 per kilowatt-hour (kWh) for the period of June 1 through December 31,
2000, compared to $0.042 per kWh during the same period in 1999. The Utility was
only permitted to collect approximately $0.054 per kWh in frozen retail rates
from its customers during that period. The increased cost of the purchased
electricity strained the financial resources of the Utility. Because of the rate
freeze, the Utility has been unable to pass on the increases in power costs to
its customers.
Because the Utility was unable to pass through the increase to its customers, it
continued to finance the higher costs of wholesale power. During the third and
fourth quarter of 2000, the Utility increased its lines of credit to $1,850
million (a net increase of $850 million), issued $1,240 million of debt under a
364-day facility, and issued $680 million of five-year notes.
In November 2000, the Utility filed a proposed Rate Stabilization Plan (RSP),
which sought to end the rate freeze and thereby enable the Utility to pass on
the increased wholesale electric costs to customers through increased rates. The
CPUC evaluated the Utility's proposal, and on January 4, 2001, denied the
Utility's request for a rate increase. Instead, the CPUC allowed the Utility to
establish an interim energy procurement surcharge of $0.01 per kWh, to remain in
effect for 90 days from the effective date of the decision. This increase,
which could not be used to recover past procurement costs, resulted in
approximately $70 million of additional revenue per month, which was not
sufficient to cover the higher wholesale costs of electricity, nor did it help
with the costs already incurred.
The Utility accumulated a total of $6.9 billion in under-collected power costs
and generation-related transition costs at December 31, 2000. The
under-collected purchased power costs generally would be deferred for future
recovery as a regulatory asset subject to future collection from customers in
rates. However, due to the lack of regulatory, legislative, or judicial relief,
the Utility determined that it could no longer conclude that its uncollected
wholesale electricity costs and remaining transition costs were probable of
recovery in future rates. Therefore, the Utility charged to earnings the
under-
16
collected electricity costs and the unamortized transition costs at December 31,
2000. For the three- and nine-month periods ended September 30, 2001, the
Utility has expensed all power generation and procurement costs as incurred.
Beginning in the second quarter of 2001, the Utility's generation-related
component of electric revenues was greater than its generation-related costs.
This differential resulted in an increase to earnings of $687 million and $124
million for the three- and nine-month periods ending September 30, 2001, and
represents the partial recovery of previously written off generation-related
transition costs. This includes $327 million (after-tax) related to the market
value of certain terminated bilateral contracts.
As a result of the Utility's inability to pass through wholesale electricity
costs to customers, and its impact on the Utility's financial resources, PG&E
Corporation's and the Utility's credit rating deteriorated to below investment
grade in January 2001. This credit downgrade precluded PG&E Corporation and the
Utility from access to capital markets. Beginning in January 2001, PG&E
Corporation and the Utility began to default on maturing commercial paper. In
addition, the Utility became unable to pay the full amount of invoices received
for wholesale power purchases and made only partial payments. The Utility had no
credit under which it could purchase wholesale electricity on behalf of its
customers on a continuing basis. Consequently, generators were only selling to
the Utility under emergency action taken by the U.S. Secretary of Energy.
Further affecting the rate freeze and the timing of the recovery of the
transition costs, in March 2001, the CPUC adopted The Utility Reform Network's
(TURN) proposal to transfer on a monthly basis the balance in the Utility's
Transition Revenue Account (TRA) to the Transition Cost Balancing Account
(TCBA). The TRA is a regulatory balancing account that is credited with total
revenue collected from ratepayers through frozen rates and which tracks
under-collected power purchase costs. The TCBA is a regulatory balancing account
that tracks the recovery of generation-related transition costs. The accounting
changes are retroactive to January 1, 1998. The Utility believes the CPUC is
retroactively transforming the power purchase costs in the TRA into transition
costs in the TCBA. However, the CPUC characterized the accounting changes as
merely reducing the prior revenues recorded in the TCBA, thereby affecting only
the amount of transition cost recovery achieved to date. The CPUC also ordered
the utilities to restate and to record their generation memorandum account
balances to the TRA on a monthly basis before any transfer of generation
revenues to the TCBA. The CPUC found that based on the accounting changes, the
conditions for meeting the end of the rate freeze have not been met.
The Utility filed an application for rehearing of the CPUC's retroactive
accounting change alleging that the adoption of the accounting change violates
AB 1890, exceeds the CPUC's authority, constitutes an unconstitutional taking of
the Utility's property, violates the Utility's federal and state due process and
equal protection rights, and constitutes unlawful retroactive ratemaking. The
CPUC has not acted on the application for rehearing. Nonetheless, the CPUC's
decision does not alter or otherwise affect the amount or nature of wholesale
electricity procurement and transition costs that the Utility has incurred or
the amount of the Utility's retail rate revenues available to pay for those
wholesale costs. The Utility believes the decision neither complies with
controlling federal law nor furnishes a basis for the CPUC to avoid such
compliance. The Utility requested that the Bankruptcy Court enjoin the CPUC from
requiring the Utility to implement the regulatory accounting changes. On June 1,
2001, the Bankruptcy Court denied the Utility's application for a preliminary
injunction, and an appeal of the Bankruptcy Court's decision is now pending.
Under the California electric industry restructuring legislation, the market
valuation of the Utility's remaining generation assets (primarily its
hydroelectric facilities) must be completed by December 31, 2001. Any excess of
market value over the assets' book value would be used to offset the Utility's
17
transition costs. The Utility has submitted testimony to the CPUC that it
believes the market value of its hydroelectric generating facilities is $4.1
billion. Based on that value and after restating its regulatory accounts to
comply with the CPUC's March 2001 accounting order, the Utility believes it
would have recovered its transition costs as early as March 2000 when the
Utility had not yet incurred any under-collected power procurement costs on
behalf of its retail customers. However, the CPUC has not yet accepted the
Utility's estimated market valuation of its hydroelectric assets nor has the
CPUC determined that the rate freeze has ended.
On March 27, 2001, the CPUC authorized an average increase in retail rates of
$0.03 per kWh, which was in addition to the emergency $0.01 per kWh interim
surcharge as discussed above. The revenue generated by this rate increase was to
be used only for power procurement costs that are incurred after March 27, 2001
and could not be used to pay amounts owed to creditors. Although the rate
increase was authorized immediately, the Utility did not begin collecting in
rates the $0.03 per kWh surcharge until June 1, 2001, when the rate design was
adopted by the CPUC. Accordingly, the CPUC authorized an additional interim
$0.005 per kWh increase to be collected from ratepayers from June 1, 2001 to
June 1, 2002.
California Department of Water Resources Purchases
In January 2001, the California Legislature and the Governor of California
authorized the California Department of Water Resources (DWR) to begin
purchasing wholesale electric energy on behalf of the Utility's retail
customers. On February 1, 2001, the Governor signed into law AB 1X authorizing
the DWR to enter into contracts for the supply of electricity. In addition to
certain contracts it has subsequently entered into, the DWR continues to
purchase power on the spot market at prevailing market prices.
On March 27, 2001, the CPUC issued an interim order requiring the Utility and
the other California investor-owned utilities to pay the DWR a per-kWh price for
the power purchased by the DWR for the Utility's customers. The CPUC determined
that the generation-related component of retail rates should be the total
bundled electric rate less the following non-generation related rates or
charges: transmission, distribution, public purpose programs, nuclear
decommissioning, and the fixed transition amount. The CPUC determined that the
company-wide average generation related rate is $0.06471 per kWh before June 1,
2001. On March 27, 2001, the CPUC adopted an additional rate surcharge of $0.03
per kWh. The additional surcharge did not go into effect until June 1, 2001, at
which time it was increased by approximately $0.005 per kWh for twelve months to
amortize the under-collection in surcharge revenues that occurred between March
27 and June 1, 2001. The resulting generation rate is $0.09987 per kWh. The CPUC
ordered the Utility to pay the DWR within 45 days after the DWR supplies power
to its retail customers, subject to penalties for each day that the payment is
late.
The Utility has acted as an agent for the DWR with respect to the collection of
the portion of the Utility's retail rates that must be paid to the DWR for the
purchases of power on behalf of the Utility's customers.
Initially, the DWR indicated that it intended to buy power only at "reasonable
prices" to meet the Utility's net open position (the amount of power needed by
retail electric customers that cannot be met by utility-owned generation or
power under contract to the Utility), leaving the ISO to purchase the remainder
in order to avoid blackouts. The ISO billed the Utility for its costs to
purchase power to cover the amount of the Utility's net open position not
covered by the DWR. The Utility does not believe it is responsible to pay for
the ISO's purchases (see ISO Purchases below).
18
On June 21, 2001, the Utility received a request from the DWR that the Utility
pay the DWR for the DWR's out-of-market purchases made on behalf of the
Utility's customers between January 17, 2001 and June 2, 2001, pursuant to AB
1X. It is unclear how much of the ISO's power purchases have been made by the
DWR on behalf of the Utility's customers. The Utility has previously received
invoices from the ISO for what the Utility believes may be the same energy.
Since the Utility is merely a collection agent for the DWR's costs and related
revenues, the Utility does not reflect these amounts in its Condensed
Consolidated Statements of Operations. For the nine-month period ended September
30, 2001, electricity billings to the Utility's customers totaled $7,058 million
of which the portion attributable to the DWR totaled $1,793 million. The Utility
records these pass-through amounts based on the CPUC's interim order on March
27, 2001 at the generation-related rate per kWh, and not based on the proposed
DWR revenue requirement discussed below.
On July 23, 2001, the DWR filed information concerning its revenue requirement
with the CPUC. The DWR stated that it seeks to collect $13.072 billion from the
electric customers of the three California investor-owned utilities for the
period January 17, 2001 through December 2002. Of this amount, the DWR seeks to
collect approximately $5.2 billion from the Utility's customers. The DWR's
filing indicated that the average cost it is seeking from California utility
customers is $0.108 per kWh for 2001 and $0.137 per kWh in 2002. On July 24,
2001, the Utility requested that the DWR hold a public hearing on its revenue
requirement because the DWR's filing lacked sufficient detail to determine the
impact of its revenue requirement on ratepayers and the Utility.
On September 4, 2001, a CPUC Administrative Law Judge (ALJ) issued a proposed
decision (PD) establishing DWR charges for the three California utilities. The
PD would allocate the DWR revenue requirement among the three California
utilities on a "cost of service" basis, causing the Utility's share of the DWR
revenue requirement to be approximately $6.5 billion, which is higher than the
"equal cents per kWh" allocation recommended by DWR. However, the PD would not
change the Utility's retail rates. Evidentiary hearings in the DWR's cost
allocation proceedings are scheduled to begin on November 13, 2001.
On October 19, 2001, the DWR issued a draft revised revenue requirement, which
reduces its overall revenue requirement statewide to $10.2 billion for the
two-year period 2001 to 2002. The reasons for the reduction include lower spot
power prices and lower gas prices under which some of DWR's power contracts are
indexed. The DWR intends to formally submit this revised revenue requirement to
the CPUC in the near future after considering public comments. The revised DWR
revenue requirement does not resolve issues relating to allocation of DWR's
costs among the three utilities, which are pending before the CPUC in a separate
proceeding. Nor does the DWR revised revenue requirement resolve issues
concerning how the DWR request would be reconciled with the Utility's existing
rates, including those for its retained generation facilities.
Finally, the revised DWR revenue requirement does not address the dispute
between the DWR and the CPUC regarding the form and substance of a rate
agreement which the DWR has requested for the purpose of financing its bonds,
but which the CPUC rejected on October 4, 2001.
ISO Purchases
As previously stated, the ISO billed the Utility for its costs to purchase power
to cover the Utility's net open position not covered by the DWR. The Utility
believes that since it has not met the creditworthiness standards under the
ISO's tariff since early January 2001, the Utility should not be responsible for
the
19
ISO's purchases made to meet the Utility's net open position.
On February 14, 2001, the Federal Energy Regulatory Commission (FERC) ordered
that the ISO could only buy power on behalf of creditworthy entities. The FERC
order also stated that the ISO could continue to schedule power for the Utility
as long as it comes from its own generation units and is routed over its own
transmission lines. Despite the FERC orders, the ISO continued to bill the
Utility for the ISO's wholesale power purchases.
On April 6, 2001, the FERC issued a further order directing the ISO to implement
its prior order, which the FERC clarified, applying to all third-party
transactions whether scheduled or not. In light of the FERC's April 6, 2001
order, the Utility has not recorded any such estimated ISO charges after April
6, 2001, except for the ISO's grid management charge. However, the Utility has
accrued the full amount of the ISO's previous charges of approximately $1
billion, since the Utility was not creditworthy through April 6, 2001, in the
accompanying financial statements. On June 13, 2001, the FERC denied the ISO's
request for rehearing of its April 6, 2001 order. The Utility believes it is not
responsible for these costs since it has not met the creditworthiness standards
under the ISO tariff since early January 2001.
Furthermore, on June 26, 2001, the Bankruptcy Court issued a preliminary
injunction prohibiting the ISO from charging the Utility for the ISO's wholesale
power purchases made in violation of bankruptcy law, the ISO's tariff, and the
FERC's February 14 and April 6, 2001 orders. In issuing the injunction, the
Bankruptcy Court noted that the FERC orders permit the ISO to schedule
transactions that involve either a creditworthy buyer or a creditworthy
counter-party, and noted the existence of unresolved issues regarding how to
ensure these creditworthiness requirements for real-time transactions and
emergency dispatch orders issued by the ISO to power sellers.
A proceeding is pending before the FERC to consider potential refunds for
wholesale prices paid to power sellers for purchases made in the ISO and PX spot
markets between October 2, 2000 and June 20, 2001. A decision is not expected
until the second quarter of 2002.
QF Contracts
As a result of the energy crisis and the Utility's Bankruptcy filing, a number
of QFs requested the Bankruptcy Court to either terminate their contracts
requiring them to sell power to the Utility or have the contracts suspended for
the summer of 2001 so the QFs can sell power at market-based rates. In July
2001, the Utility signed five-year agreements with 197 of its QFs, ensuring the
Utility and its customers receive a reliable supply of electricity at an average
energy price of $0.0537 per kWh. Under the terms of the agreements, the Utility
will assume the QF contracts and pay the pre-petition debt on these 197 QF
contracts, totaling $845 million, on the effective date of the Plan. The total
amount the Utility owed to QFs when it filed for bankruptcy protection was
approximately $1 billion. The agreements represent 85% of debt owed to QFs. For
certain of these QFs, if the effective date has not occurred by July 15, 2003,
the Utility will pay 2% of the principal amount of the pre-petition debt per
month until the effective date of the Plan or until July 15, 2005, when it will
pay the remaining pre-petition debt. By locking into the average fixed cost, the
Utility will help protect its customers from the price fluctuations in the
wholesale market. Each of the agreements requires formal approval from the
Bankruptcy Court. Most of the agreements have already been approved by the
Bankruptcy Court, and the Utility will be making filings for the remainder in
the near future.
20
Bilateral Contracts
As a response to the energy crisis, in October 2000, the Utility entered into
multiple bilateral contracts with suppliers for long-term electricity
deliveries. However, some of these contracts were terminated by the
counter-parties who were entitled to do so in the event of the Utility
triggering early termination provisions caused by the filing for Chapter 11
bankruptcy protection and the decline in the Utility's credit quality to below
investment grade. The terms of the contracts require that at termination, the
contracts be settled at the then market value of the contract. One contract has
been settled with the counter-party for $426 million. The parties are
negotiating various issues regarding the two remaining contracts. The settled
contract and the estimated market value for the contracts under negotiation
total $552 million and have been recognized as a reduction to the Cost of
Electric Energy in the Condensed Consolidated Statements of Operations. As of
September 30, 2001, remaining individual contracts range in size from
approximately 30,800 megawatt hours (MWh) to 3,504,000 MWhs of supply annually.
The contracts extend to 2003.
The Utility had PX block-forward contracts, which were seized by California
Governor Gray Davis in February 2001 for the benefit of the state, acting under
California's Emergency Services Act (the Act). The block-forward contracts had
an estimated unrealized gain of $243 million at the time they were seized. The
Utility, the PX, and some of the PX market participants have filed
administrative claims and state court litigation against the State to recover
the value of the seized contracts. The administrative claims, as well as the
state court litigation, are pending.
Note 3: VOLUNTARY PETITION FOR RELIEF UNDER CHAPTER 11 AND PLAN OF
REORGANIZATION
On April 6, 2001, the Utility filed a voluntary petition for relief under
Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Under Chapter 11, the
Utility retains control of its assets and is authorized to operate its business
as a debtor-in-possession while being subject to the jurisdiction of the
Bankruptcy Court. Subsidiaries of the Utility, including PG&E Funding LLC (which
holds Rate Reduction Bonds,) and PG&E Holdings LLC (which holds stock of the
Utility), are not included in the Utility's petition. The Utility's Condensed
Consolidated Financial Statements have been prepared in accordance with the
American Institute of Certified Public Accountants' Statement of Position 90-7
(SOP 90-7), Financial Reporting by Entities in Reorganization Under the
Bankruptcy Code, and on a going concern basis, which contemplates continuity of
operation, realization of assets and liquidation of liabilities in the ordinary
course of business. However, as a result of the filing, such realization of
assets, and liquidation of liabilities are subject to uncertainty.
Certain claims against the Utility in existence prior to its filing of the
petition for relief are stayed while the Utility continues business operations
as a debtor-in-possession. The Utility has reflected its estimate of all such
valid claims in the September 30, 2001, Condensed Consolidated Balance Sheets as
Liabilities Subject to Compromise. Additional claims or changes to Liabilities
Subject to Compromise may arise subsequent to the filing date resulting from:
1. Negotiations,
2. Rejection of executory contracts, including leases,
3. Actions by the Bankruptcy Court,
4. Further developments with respect to disputed claims,
5. Proofs of claim, or
6. Other events
21
Payment terms for these amounts will be established through the bankruptcy
proceedings. Claims secured against the Utility's assets (secured claims) also
are stayed, although the holders of such claims have the right to move the court
for relief from the stay. Secured claims are secured primarily by liens on
substantially all of the Utility's assets and by pledged accounts receivable
from gas customers. The Bankruptcy Court has approved making the regular
interest payments on the Utility's secured debt.
On September 20, 2001, the Utility and its parent company, PG&E Corporation,
jointly filed with the Bankruptcy Court a proposed plan of reorganization (the
Plan) of the Utility under the Bankruptcy Code and their proposed disclosure
statement describing the Plan. To approve the form of disclosure statement, the
Bankruptcy Court must determine that it contains adequate information to make an
informed judgment in voting to accept or reject the Plan. The Bankruptcy Court
has set a hearing date of December 19, 2001, to consider the adequacy of the
disclosure statement. Upon Bankruptcy Court approval, the disclosure statement
will be sent to holders of claims against, and equity interests in, the Utility
in connection with the solicitation of acceptances of the Plan. Bankruptcy Court
approval of the disclosure statement does not constitute a determination by the
Bankruptcy Court as to the merits of the Plan or an indication that the
Bankruptcy Court will confirm the Plan.
If the court approves the disclosure statement by the end of 2001, the
confirmation process could occur as early as the spring of 2002. Among the
requirements for confirmation are that the Plan is:
1. Accepted by all impaired classes of claims and equity interests or, if
rejected by an impaired class, that the Plan does not discriminate
unfairly and is fair and equitable as to such class,
2. Feasible, and
3. In the best interests of creditors and shareholders that are impaired
under the Plan.
The proposed Plan would create three new California limited liability companies
and separate the Utility's operations into four lines of business: gas and
electric distribution (the reorganized Utility), electric transmission (ETrans),
gas transmission (GTrans), and electric generation (Gen)(collectively, the
Internal Restructuring). PG&E Corporation and the Utility believe that the Plan
will enable the Utility to successfully reorganize its business and accomplish
the objectives of Chapter 11 of the Bankruptcy Code, and that acceptance of the
Plan is in the best interests of the Utility, its creditors and all parties in
interest. Throughout the process of developing the Plan, PG&E Corporation and
the Utility have been working closely with the Official Committee of Unsecured
Creditors (the Committee). On October 2, 2001, the Utility filed with the
Bankruptcy Court the Support Agreement between the Utility and the Committee
under which the Committee has agreed to support the Plan under the conditions
specified in the agreement.
Under the Plan, the majority of the assets and liabilities associated with the
Utility's electric transmission business would be transferred to ETrans, the
majority of the assets and liabilities associated with the Utility's gas
transmission business would be transferred to GTrans, and the majority of the
assets and liabilities associated with the Utility's generation business
(including the conventional hydroelectric generating plants, the Helms Pumped
Storage Plant, the Diablo Canyon Nuclear Power Plant, beneficial interests in
the Diablo Canyon Nuclear Facilities Decommissioning Master Trust, and the
irrigation district power purchase contracts) would be transferred to Gen. The
Plan further contemplates that the Utility would create a separate holding
corporation (Newco) to hold the membership interests of each of ETrans, GTrans
and Gen, and that the Utility would be the sole shareholder of Newco. After the
transfer of Utility assets to the newly-formed entities or their subsidiaries or
affiliates, the
22
Utility would distribute the outstanding common stock of Newco to PG&E
Corporation, and each of ETrans, GTrans and Gen would thereafter be an indirect
wholly-owned subsidiary of PG&E Corporation.
The Plan contemplates that on or as soon as practicable after the date on which
the Plan becomes effective (the Effective Date), PG&E Corporation will
distribute the shares of the reorganized Utility's common stock it holds to the
holders of PG&E Corporation common stock on a pro rata basis (the Spin-Off). The
reorganized Utility would thereafter operate as a stand-alone electric and gas
distribution business, would continue to own the majority of Utility assets, and
would continue to provide electric and gas distribution services to customers.
Pursuant to the Plan, the Utility's currently outstanding preferred stock would
remain in place as shares of preferred stock of the reorganized Utility. It is
contemplated that holders of preferred stock would receive on the Effective
Date, and in cash, any dividends unpaid and sinking fund payments accrued in
respect of such preferred stock through the last scheduled payment date before
the Effective Date. The common stock of the reorganized Utility would be
registered pursuant to the Securities Exchange Act of 1934, and would generally
be freely tradable by the recipients on the Effective Date or as soon as
practicable thereafter. The reorganized Utility would apply to list the common
stock of the reorganized Utility on the New York Stock Exchange.
In addition, the Plan proposes that all valid creditor claims will be paid in
full with interest, using a combination of cash and long-term notes. The
majority of creditors, those with allowed claims of $100,000 or less, will
receive cash payments for the full amount of their allowed claims on the
effective date of the Plan. The majority of secured creditors will also receive
100% of their allowed claims in cash. Finally, unsecured creditors with allowed
claims in excess of the $100,000 threshold will be paid 60% in cash and 40% in
long-term notes.
Pursuant to the Plan and as discussed further in Note 2, the reorganized Utility
would seek a Bankruptcy Court order prohibiting the Utility from reassuming the
responsibility to purchase power to meet the net open position not already
provided through the DWR's power purchase contracts, until such time as:
1. The reorganized Utility establishes an investment grade credit rating
and receives assurances that its credit rating will not be downgraded
as a result of the reassumption of the obligation to meet the net open
position,
2. There is an objective retail rate recovery mechanism in place pursuant
to which the reorganized Utility is able to fully recover in a timely
manner its wholesale costs of purchasing electricity to meet the net
open position,
3. There are objective standards in place regarding pre-approval of
procurement transactions, and
4. After reassumption of the obligation to meet the net open position, the
conditions in clauses (2) and (3) remain in effect.
The Utility also would seek a Bankruptcy Court order prohibiting the reorganized
Utility from accepting the assignment, directly or indirectly, of wholesale
electric power procurement contracts executed by the DWR. Also, pursuant to the
Plan, Gen and the reorganized Utility would enter into a 12-year bilateral power
sales agreement under which the reorganized Utility would purchase output
generated by Gen's facilities and procured under its power purchase agreements.
Implementation of the Plan is subject to obtaining certain regulatory approvals
from certain government agencies, including among others, the FERC, the SEC, the
CPUC, and the Nuclear Regulatory Commission (NRC). Additionally, because the
Internal Restructuring is intended to qualify as tax-free reorganizations and
the Spin-Off is intended to qualify as a tax-free spin-off, PG&E Corporation and
the
23
Utility will seek a private letter ruling from the Internal Revenue Service
confirming the tax-free treatment of these transactions.
The Plan asks the Bankruptcy Court to issue the following orders:
1. Approve the Plan documents, authorizing the Utility to execute, enter
into and deliver the Plan documents and to execute, implement and take
all actions necessary or appropriate to give effect to the
transactions contemplated by the Plan and the Plan documents,
2. Determine that the Utility, PG&E Corporation and their affiliates are
not liable or responsible for any DWR power contracts or purchases of
power by the DWR, and any liabilities associated therewith,
3. Prohibit the reorganized Utility from accepting an assignment of the
DWR contracts,
4. Prohibit the reorganized Utility from reassuming the net open position
unless the conditions discussed above are satisfied,
5. Approve the execution of the proposed power sales contract between Gen
and the reorganized Utility and a proposed gas transmission and
storage contract between GTrans and the reorganized Utility,
6. Prohibit the CPUC and the state of California from taking any action
related to the allocation or other treatment of any gain on sale
related to assets transferred or disposed of under the Plan that would
adversely impact the value or usefulness of any assets of the
reorganized Utility,
7. Find that the CPUC affiliate transaction rules are not applicable to
the restructuring transactions,
8. Find that the approval of state and local agencies of California,
including, but not limited to, the CPUC, shall not be required in
connection with the restructuring transactions because Section 1123 of
the Bankruptcy Code preempts such state and local laws,
9. Find that neither PG&E Corporation nor the Utility is required to
comply with certain provisions of the California Corporations Code
relating to corporate distributions and the sale of substantially all
of a corporation's assets because Section 1123 of the Bankruptcy Code
preempts such state law, and
10. Approve the commitment of ETrans to join a FERC-approved Regional
Transmission Organization (RTO) and authorizing ETrans to join such
FERC-approved RTO at such time as it is operational.
In addition, the confirmation order must be, in form and substance, acceptable
to PG&E Corporation and the Utility. Any of these conditions may be waived by
PG&E Corporation and the Utility.
The Plan provides that it will not become effective unless and until the
following conditions shall have been satisfied or waived:
1. The confirmation order, in form and substance acceptable to PG&E
Corporation and the Utility, shall have been signed by the Bankruptcy
Court on or before June 30, 2002, and shall have become a final order,
2. The Effective Date shall have occurred on or before January 1, 2003,
3. All actions, documents and agreements necessary to implement the Plan
shall have been effected or executed,
4. PG&E Corporation and the Utility shall have received all
authorizations, consents, regulatory approvals, rulings, letters,
no-action letters, opinions or documents that are determined by PG&E
Corporation and the Utility to be necessary to implement the Plan,
5. Standard & Poor's (S&P) and Moody's Investors Service (Moody's) shall
have established credit ratings for each of the securities to be
issued by the reorganized Utility, ETrans, GTrans, and Gen that are
acceptable to PG&E Corporation and the Utility,
6. The Plan shall not have been modified in a material way since the
confirmation date, and
24
7. The disaggregated entities shall have consummated each of the debt
offerings contemplated by the Plan.
If one or more of the conditions to the Effective Date described above have not
occurred or been waived by January 1, 2003:
1. The confirmation order shall be vacated,
2. No distributions under the Plan shall be made,
3. The Utility and all holders of claims and equity interests shall be
restored to the status quo ante as of the day immediately preceding
the confirmation date as though the confirmation date never occurred,
and
4. The Utility's obligations with respect to claims and equity interests
shall remain unchanged.
Although PG&E Corporation and the Utility are not able to predict all of the
factors that may affect whether the Plan will be confirmed, or whether, if
confirmed, it will become effective, some of the factors that could affect the
outcome materially include: the pace of the Bankruptcy Court proceedings; the
extent to which the Plan is amended or modified; legislative and regulatory
initiatives regarding deregulation and restructuring of the electric and natural
gas industries in the United States, particularly in California; whether the
Utility is able to obtain timely regulatory approvals or whether the Utility is
able to obtain regulatory approvals at all; risks relating to the issuance of
new debt securities by each of the disaggregated entities, including higher
interest rates than are assumed in the financial projections which could affect
the amount of cash raised to satisfy allowed claims, and the inability to
successfully market the debt securities due to, among other reasons, an adverse
change in market conditions or in the condition of the disaggregated entities
before completion of the offerings; whether the Bankruptcy Court exercises its
authority to pre-empt relevant non-bankruptcy law and if so, whether, and the
extent to which such assertion of jurisdiction is successfully challenged;
whether a favorable tax ruling or opinion is obtained regarding the tax-free
nature of the Internal Restructuring and the Spin-Off; and the ability of the
Utility to successfully disaggregate its businesses. However, the Utility
believes, based on information presently available to it, that cash available
from operations will provide sufficient liquidity to allow it to continue as a
going concern for the foreseeable future.
NOTE 4: PRICE RISK MANAGEMENT
PG&E Corporation's net gain (loss) on trading contracts for the three- and
nine-month periods ended September 30, 2001, are $44 million and $166 million,
respectively.
PG&E Corporation's and the Utility's ineffective portion of changes in fair
values of cash flow hedges are immaterial for the three- and nine-month periods
ended September 30, 2001. PG&E Corporation's and the Utility's estimated net
derivative gains or losses included in accumulated other comprehensive loss at
September 30, 2001 that are expected to be reclassified into earnings within the
next twelve months are net losses of $39 million and $0.2 million, respectively.
The actual amounts reclassified from accumulated other comprehensive loss to
earnings can differ as a result of market price changes.
The schedule below summarizes the activities affecting accumulated other
comprehensive income (loss) from derivative instruments for the three- and
nine-month periods ended September 30, 2001.
25
Three months ended Nine months ended
September 30, 2001 September 30, 2001
------------------- -------------------
PG&E PG&E
Corpor- Corpor-
(in millions) ation Utility ation Utility
------- ------- ------- -------
Beginning derivative gains (losses) included in
accumulated other comprehensive income (loss) $ (106) $ (41) $ (243) $ 90
Net gain (loss) of current period hedging
transactions 21 1 170 (6)
Net reclassification to earnings 43 40 31 (84)
------- ------- ------- -------
Ending derivative gains (losses) included in
accumulated other comprehensive loss (42) - (42) -
Foreign currency translation adjustment (5) (2) (5) (2)
------- ------- ------- -------
Ending accumulated other comprehensive loss
at September 30, 2001 $ (47) $ (2) $ (47) $ (2)
======= ======= ======= =======
Credit Risk
The use of financial instruments to manage the risks associated with changes in
energy commodity prices creates exposure resulting from the possibility of
non-performance by counter-parties pursuant to the terms of their contractual
obligations. The counter-parties associated with the instruments in PG&E
Corporation's and the Utility's portfolio consist primarily of investor-owned
and municipal utilities, energy trading companies, financial institutions, and
oil and gas production companies. PG&E Corporation and the Utility minimize
credit risk by dealing primarily with creditworthy counter-parties in accordance
with established credit approval practices and limits. PG&E Corporation assesses
the financial strength of its counter-parties at least quarterly and requires
that counter-parties post security in the form of cash, letters of credit,
corporate guarantees of acceptable credit quality, or eligible securities if
current net receivables and replacement cost exposure exceed contractually
specified limits.
PG&E Corporation and the Utility did not experience any losses due to the
non-performance of counter-parties during the three- and nine-month periods
ended September 30, 2001. At September 30, 2001, PG&E Corporation's and the
Utility's gross credit risk exposure amounted to $870 million and $83 million,
respectively. Counter-parties considered to be investment grade or higher
comprise 78% and 94% of the total credit exposure for PG&E Corporation and the
Utility, respectively.
NOTE 5: SHORT-TERM BORROWINGS AND CREDIT FACILITIES
PG&E National Energy Group
In order to support their energy trading operations and other working capital
requirements, PG&E National Energy Group (PG&E NEG) entered into a $550 million
revolving credit facility on June 15, 2001. This facility, which has an initial
term of 364 days, provides for bank borrowings and letters of credit. Borrowings
under the facility bear interest based on LIBOR plus a credit spread of 1.75%,
which is based on PG&E NEG's BBB rating for this instrument. On August 23, 2001,
this facility was increased to $1.25 billion. At September 30, 2001, $156
million of letters of credit, and borrowings of $295 million were outstanding
under this facility.
On June 18, 2001, PG&E NEG reduced one of its $550 million revolving credit
26
facilities at PG&E Generating Company, LLC (GenLLC) to $500 million to meet the
requirements of the new facility, described above. On August 23, 2001, this
facility and a $550 million 5-year revolving credit facility, at GenLLC, were
cancelled.
NOTE 6: LONG-TERM DEBT
PG&E Corporation
Commencing on March 2, 2001, PG&E Corporation refinanced its debt obligations
with $1 billion in aggregate proceeds from two term loans under a common credit
agreement with General Electric Corporation and Lehman Commercial Paper Inc.,
maturing on March 1, 2003. In accordance with the credit agreement, the
proceeds, together with other PG&E Corporation cash, were used to pay $501
million in commercial paper (including $457 million of commercial paper on which
PG&E Corporation had defaulted), $434 million in borrowings under PG&E
Corporation's long-term revolving credit facility, and $109 million to PG&E
Corporation shareholders of record as of December 15, 2000, in satisfaction of a
defaulted fourth quarter 2000 dividend. Further, approximately $99 million was
used to pre-pay the first year's interest under the credit agreement and to pay
transaction expenses associated with the debt restructuring.
PG&E Corporation itself had cash and short-term investments of $256 million at
September 30, 2001, and believes that the funds will be adequate to maintain its
continuing operations through 2002. In addition, PG&E Corporation believes that
the holding company and its non-CPUC regulated subsidiaries are protected from
the bankruptcy of the Utility.
PG&E NEG
On May 22, 2001, PG&E NEG issued senior notes in an aggregate principal amount
of $1 billion. These notes, which mature on May 16, 2011, bear interest at
10.375% and require semiannual interest payments on May 15 and November 15. On
July 27, 2001, PG&E NEG registered the bonds in an S-4 registration with the SEC
and commenced an exchange offer to allow the senior note holders to exchange
their senior notes for exchange notes with substantially similar terms as the
senior notes. The senior notes were exchanged by October 1, 2001 to exchange
notes.
PG&E NEG has used a portion of the proceeds and intends to use the balance of
the senior notes issuance, net of $28 million of debt discount and note issuance
costs, to pay down existing revolving debt, fund investments in generating
facilities and pipeline assets, working capital requirements and other general
corporate requirements.
On September 6, 2001, a subsidiary of PG&E NEG entered into a credit agreement
for $69.4 million. The debt facility will be used to fund construction of the
Plains End project. This facility expires upon the earlier of five years after
commercial operations have been declared or September 30, 2007. The facility
provides for borrowings that bear interest based on LIBOR plus a credit spread.
On September 19, 2001 and September 27, 2001, the subsidiary executed accreting
and amortizing interest rate swaps and forwards to hedge approximately 80% of
loans expected to be drawn.
During 2000 and 1999, two indirect wholly owned subsidiaries of PG&E NEG entered
into two commitments relating to the acquisition of turbine equipment and two
commitments relating to generation projects that are under construction, for
27
which they act as the construction agent for the owners. Upon completion of the
construction projects, expected to be in 2002, PG&E NEG will lease these
facilities under lease terms of five years and three years, respectively. At the
conclusion of each of the lease terms, PG&E NEG has the option to extend the
leases at fair market value, purchase the projects, or act as remarketing agent
for the lessors for sales to third parties. If PG&E NEG elects to remarket the
projects, then PG&E NEG would be obligated to the lessors for up to 85% of the
project costs if the proceeds are deficient to pay the lessor's investors. PG&E
Corporation has committed to fund up to $604 million in the aggregate of equity
to support PG&E NEG's obligation to the lessors during the construction and
post-construction periods. In addition, PG&E NEG entered into operative
agreements with a special purpose entity that will own and finance construction
of another facility totaling $775 million. PG&E Corporation has committed to
fund up to $122 million of equity support commitments to meet the obligations to
the entity. In 2001, PG&E NEG replaced PG&E Corporation equity support
commitments with substitute commitments of PG&E NEG. The trusts associated with
these facilities have been consolidated in the accompanying financial
statements.
NOTE 7: 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% 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 $9
million. The Trust in turn used the net proceeds from the QUIPS offering and
issuance of the common stock securities to purchase subordinated debentures
issued by the Utility with a face value of $309 million, due 2025. These
subordinated debentures are the only assets of the Trust. Proceeds from the sale
of the subordinated debentures were used to redeem and repurchase higher-cost
preferred stock.
The Utility's guarantee of the QUIPS, considered together with the other
obligations of the Utility with respect to the QUIPS, constitutes a full and
unconditional guarantee by the Utility of the Trust's contractual obligations
under the QUIPS issued by the Trust. The subordinated debentures may be redeemed
at the Utility's option at par value plus accrued interest through the
redemption date. The proceeds of any redemption will be used by the Trust to
redeem QUIPS in accordance with their terms.
Upon liquidation or dissolution of the Utility, holders of these QUIPS would be
entitled to the liquidation preference of $25 per share plus all accrued and
unpaid dividends thereon to the date of payment.
On March 16, 2001, the Utility deferred quarterly interest payments on the
Utility's 7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025,
until further notice in accordance with the indenture. The corresponding
quarterly payments on the 7.90% QUIPS, issued by the Trust, due on April 2,
2001, have been similarly deferred. Distributions can be deferred up to a period
of five years under the terms of the indenture. Per the indenture, investors
will accumulate interest on the unpaid distributions at the rate of 7.90%.
On April 12, 2001, Bank One, N.A., as successor-in-interest to The First
National Bank of Chicago, gave notice that an Event of Default exists under the
Trust Agreement in that the Utility on April 6, 2001, filed a voluntary petition
for relief under the Bankruptcy Code. Pursuant to the Trust Agreement, the
bankruptcy filing by the Utility constitutes an Early Termination Event. The
28
Trust Agreement directs that upon the occurrence of an Early Termination Event,
the Trust shall be liquidated by the Trustees as expeditiously as the Trustees
determine to be possible by distributing, after satisfaction of liabilities to
creditors of the Trust, to each Security holder a like amount of the Utility's
7.90% Deferrable Interest Subordinated Debentures, Series A, due 2025. As of
September 30, 2001, the QUIPS have been reclassified to Liabilities Subject to
Compromise on the Condensed Consolidated Balance Sheet.
NOTE 8: 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 $13 million (property damage) and $4 million (business
interruption), in each case per policy period, in the event losses exceed the
resources of NEIL. Effective November 15, 2001, the maximum retrospective
assessments will be increased to $26 million and $9 million for property damage
and business interruption, respectively.
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.
Workers' Compensation Security
The Utility must provide a guarantee to maintain its status as a self-insurer
for workers' compensation. On May 9, 2001, the State Department of Industrial
Relations (DIR) approved the Utility's security deposit of approximately $401
million in collateral provided by surety bonds. Other forms of acceptable
security besides surety bonds include letters of credit, cash, or securities.
PG&E Corporation has guaranteed the surety bonds and workers' compensation of
the Utility.
In February 2001, several surety companies provided cancellation notices, citing
concerns about the Utility's financial situation. However, the cancellation of
surety bonds is not possible unless released by the DIR. Such surety bonds
totaling $185 million guarantee workers' compensation claims prior to February
2001. However, the state has continued to apply the canceled bond amounts
towards the approved $401 million amount. The Utility was able to supplement the
difference for any new obligations since February 2001, through three additional
active surety bonds totaling $216 million. The cancelled bonds have not, to
date, impacted the Utility's self-insured status under California law, or its
ability to meet current plan obligations.
Environmental Remediation
29
Utility
The Utility may be required to pay for environmental remediation at sites where
it has been or may be a potentially responsible party under the Comprehensive
Environmental Response Compensation and Liability Act, and similar state
environmental laws. These sites include former manufactured gas plant sites,
power plant sites, and sites used by the Utility for the storage or disposal of
potentially hazardous materials. Under federal and California laws, the Utility
may be responsible for remediation of hazardous substances, even if it did not
deposit those substances on the site.
The Utility records an environmental remediation 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 the range of
possible costs, the Utility records these costs at the lower end of this range.
As of September 30, 2001, the Utility expects to spend $319 million for
hazardous waste remediation costs at identified sites, including divested
fossil-fueled power plants. The cost of the hazardous substance remediation
ultimately undertaken by the Utility is difficult to estimate. A change in
estimate may occur in the near term due to uncertainty concerning the Utility's
responsibility, the complexity of environmental laws and regulations, and the
selection of compliance alternatives. If 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 could spend as much as $471 million on these
costs. The Utility estimates the upper limit of the range using assumptions
least favorable to the Utility, based upon a range of reasonably possible
outcomes. Costs may be higher if the Utility is found to be responsible for
clean-up costs at additional sites or expected outcomes change.
The Utility had an environmental remediation liability of $319 million and $320
million at September 30, 2001, and December 31, 2000, respectively. The $319
million accrued at September 30, 2001, includes (1) $139 million related to the
pre-closing remediation liability, associated with the divested generation
facilities, and (2) $180 million related to remediation costs for those
generation facilities that the Utility still owns, manufactured gas plant sites,
and gas gathering compressor stations. Of the $319 million environmental
remediation liability, the Utility has recovered $193 million through rates, and
expects to recover another $109 million in future rates. The Utility also is
recovering its costs from insurance carriers and from other third parties as
appropriate.
On June 28, 2001, the Bankruptcy Court entered its "Order on Debtor's Motion for
Authority to Continue Its Hazardous Substances Cleanup Program." The Utility is
authorized to expend (1) up to $22 million in each calendar year in which this
Chapter 11 case is pending to continue its hazardous substance remediation
programs and procedures, and (2) any additional amounts necessary in emergency
situations involving post-petition releases or threatened releases of hazardous
substances, if such excess expenditures are necessary in the Utility's
reasonable business judgment to prevent imminent harm to public health and
safety or the environment (provided that the Utility seeks the Court's approval
of such emergency expenditures at the earliest practicable time), in each case
as described in the motion.
30
The California Attorney General, on behalf of various state environmental
agencies filed proofs of claims in the Utility's bankruptcy proceeding for
environmental claims aggregating to approximately $770 million. For most if not
all of these sites, the Utility is in the process of remediation in cooperation
with the relevant agencies or would be so in the future in the normal course of
business. In addition, for the majority of the remediation claims, the state
would not be entitled to recover these costs unless they accept responsibility
to clean up the sites, which is unlikely. Since the Plan provides that the
Utility intends to respond to these types of claims in the regular course of
business, and since the Utility has not argued that the bankruptcy proceeding
relieves the Utility of its obligations to respond to valid environmental
remediation orders, the Utility believes the claims seeking specific cash
recoveries are invalid.
In December 1999, the Utility was notified by the purchaser of its former Moss
Landing power plant that it had identified a cleaning procedure used at the
plant that released heated water from the intake, and that this procedure is not
specified in the plant's National Pollutant Discharge Elimination System (NPDES)
permit issued by the Central Coast Regional Water Quality Control Board (Central
Coast Board). The purchaser notified the Central Coast Board of its findings. In
March 2000, the Central Coast Board requested the Utility to provide specific
information regarding the "backflush" procedure used at Moss Landing. The
Utility's investigation indicated that while it owned Moss Landing, significant
amounts of water were discharged from the cooling water intake. While the
Utility's investigation did not clearly indicate that discharged waters had a
temperature higher than ambient receiving water, the Utility believes that the
temperature of the discharged water was higher than that of the ambient
receiving water. In December 2000, the executive officer of the Central Coast
Board made a settlement proposal to the Utility under which it would pay $10
million, a portion of which would be used for environmental projects and the
balance of which would constitute civil penalties. A proof of claim has been
filed by the California Attorney General in the Utility's bankruptcy proceeding
on behalf of the Central Coast Board seeking unspecified penalties for alleged
discharges of heated cooling water from Moss Landing. Settlement negotiations
are continuing.
The Utility's Diablo Canyon employs a "once through" cooling water system, which
is regulated under a NPDES Permit, issued by the Central Coast Board. This
permit allows Diablo Canyon to discharge the cooling water at a temperature no
more than 22 degrees above ambient receiving water, and requires that the
beneficial uses of the water be protected. The beneficial uses of water in this
region include industrial water supply, marine and wildlife habitat, shellfish
harvesting, and preservation of rare and endangered species. In January 2000,
the Central Coast Board issued a proposed draft Cease and Desist Order (CDO)
alleging that, although the temperature limit has never been exceeded, the
Diablo Canyon's discharge was not protective of beneficial uses. In October
2000, the Central Coast Board and the Utility reached a tentative settlement of
this matter pursuant to which the Central Coast Board has agreed to find that
the Utility's discharge of cooling water from the Diablo Canyon plant protects
beneficial uses and that the intake technology reflects the "best technology
available", under Section 316(b) of the Federal Clean Water Act. As part of the
settlement, the Utility will take measures to preserve certain acreage north of
the plant and will fund approximately $4.5 million in environmental projects
related to coastal resources. The parties are negotiating the documentation of
the settlement. The final agreement will be subject to public comment and will
be incorporated in a consent decree to be entered in California's Superior
Court. A claim has been filed by the California Attorney General in the
Utility's bankruptcy proceeding on behalf of the Central Coast Board seeking
unspecified penalties and other relief in connection with the Diablo Canyon's
operation of its cooling water system.
PG&E Corporation believes the ultimate outcome of these matters will not have a
material impact on its or the Utility's financial position or results of
31
operations.
PG&E NEG
In May 2000, PG&E NEG received an Information Request from the U.S.
Environmental Protection Agency (EPA), pursuant to Section 114 of the Federal
Clean Air Act (CAA). The Information Request asked PG&E NEG to provide certain
information, relative to the compliance of the Brayton Point and Salem Harbor
Generating Stations with the CAA. No enforcement action has been brought by the
EPA to date. PG&E NEG has had very preliminary discussions with the EPA to
explore a potential settlement of this matter. As a result of this and related
regulatory initiatives by the Commonwealth of Massachusetts, PG&E NEG is
exploring initiatives that would assist it to achieve significant reductions of
sulfur dioxide and nitrogen oxide emissions by as early as 2006 to 2010. PG&E
NEG believes that it would meet these requirements through installation of
controls at the Brayton Point and Salem Harbor plants and estimates that capital
expenditures on these environmental projects will be approximately $265 million
through 2006. PG&E NEG believes that it is not possible to predict at this point
whether any such settlement will occur or in the absence of a settlement the
likelihood of whether the EPA will bring an enforcement action.
GenLLC's existing power plants, including USGen New England, Inc. (USGenNE)
facilities, are subject to federal and state water quality standards with
respect to discharge constituents and thermal effluents. Three of the
fossil-fueled plants owned and operated by USGenNE are operating pursuant to
NPDES permits that have expired. For the facilities whose NPDES permits have
expired, permit renewal applications are pending, and it is anticipated that all
three facilities will be able to continue to operate under existing terms and
conditions until new permits are issued. It is estimated that USGenNE's cost to
comply with the new permit conditions could be as much as $60 million through
2005. It is possible that the new permits may contain more stringent limitations
than prior permits.
In September 2000, PG&E NEG settled a legal claim through certain agreements
that require PG&E NEG to alter its existing wastewater treatment facilities at
its Brayton Point and Salem Harbor generating facilities. PG&E NEG began the
activities during 2000 and is expected to complete them in 2002 as the review
and permitting process with the state has caused some delays. In addition to
costs incurred in 2000, at December 31, 2000, PG&E NEG recorded a reserve in the
amount of $3.2 million relating to its estimate of the remaining environmental
expenses to fulfill its obligations under the agreement. In addition, PG&E NEG
expects to incur approximately $4 million in capital expenditures during 2001
and into 2002 to complete the project.
LEGAL MATTERS
Utility
The Utility's Chapter 11 bankruptcy on April 6, 2001, discussed in Note 3
automatically stayed the litigation described below against the Utility.
Chromium Litigation
-------------------
Twelve civil suits are pending against the Utility in several California state
courts. One of these suits also names PG&E Corporation as a defendant. 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 1,250
32
individuals.
The Utility is responding to the suits in which it has been served and is
asserting affirmative defenses. The Utility will pursue appropriate legal
defenses, including statute of limitations, 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.
There have been approximately 1,240 claims filed with the Bankruptcy Court (by
most of the plaintiffs in the twelve cases and other individuals) alleging that
exposure to chromium in soil, air or water near the Utility's compressor
stations at Hinkley, Kettleman, or Topock, California caused personal injuries,
wrongful death or other injuries. Approximately 1,050 of these claimants have
filed claims for damages that total more than $500 million. The remaining claims
seek recovery for an unknown amount of claimed damages.
The Utility has recorded a reserve in its financial statements in the amount of
$160 million for these matters. PG&E Corporation and the Utility believe that,
after taking into account the reserves recorded as of December 31, 2000, the
ultimate outcome of this matter will not have a material adverse impact on PG&E
Corporation's or the Utility's financial condition or future results of
operations.
Federal Securities Lawsuit
--------------------------
A complaint, Gillam, et al. v. PG&E Corporation, et al., is pending in the U.S.
District Court for the Northern District of California. Certain executive
officers of PG&E Corporation have also been named as defendants. The first
amended complaint, purportedly brought on behalf of all persons who purchased
PG&E Corporation common stock or certain shares of the Utility's preferred stock
between July 20, 2000 and April 9, 2001, claims that defendants caused PG&E
Corporation's consolidated financial statements for the second and third
quarters of 2000 to be materially misleading in violation of federal securities
laws by recording as a deferred cost and capitalizing as a regulatory asset the
undercollections that resulted when escalating wholesale energy prices caused
the Utility to pay far more to purchase electricity than it was permitted to
collect from customers. Plaintiff seeks damages in excess of $2.4 billion,
punitive damages, interest, injunctive relief, and attorneys' fees.
The defendants have filed a motion to dismiss, based largely on public
disclosures by PG&E Corporation, the Utility and others regarding the
undercollections, the risk that they might not be recoverable, the financial
consequences of non-recovery, and other information from which analysts and
investors could assess for themselves the probability of recovery. The motion is
scheduled to be heard on December 10, 2001.
PG&E Corporation believes the allegations to be without merit and intends to
present a vigorous defense.
PG&E Corporation is unable to predict whether the outcome of this litigation
will have a material adverse effect on its financial condition or results of
operations.
Recorded Liability for Legal Matters
In accordance with SFAS No. 5, "Accounting for Contingencies," 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
33
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
for PG&E Corporation and the Utility:
(in millions)
Beginning balance, January 1, 2001 $ 185
Provisions for liabilities 6
Payments (2)
Adjustments 10
-----
Ending balance, September 30, 2001 $ 199
=====
NOTE 9: SEGMENT INFORMATION
PG&E Corporation has identified three reportable operating segments, which were
determined based on similarities in economic characteristics, products and
services, types of customers, methods of distributions, the regulatory
environment, and how information is reported to PG&E Corporation's key decision
makers. As discussed below, these segments represent a change in the reportable
segments. In accordance with the accounting principles generally accepted in the
United States of America, prior year segment information has been restated to
conform to the current segment presentation. The Utility is one reportable
operating segment and the other two are part of PG&E NEG. These three reportable
operating segments provide 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,
the Utility, provides natural gas and electric service to its customers.
PG&E NEG
PG&E Corporation's subsidiary, PG&E NEG, is an integrated energy company with a
strategic focus on power generation, greenfield development, natural gas
transmission, and wholesale energy marketing and trading in North America. PG&E
NEG has integrated its generation, development, and energy marketing and trading
activities to increase the returns from its operations, identify and capitalize
on opportunities to increase its generating and pipeline capacity, create energy
products in response to dynamic markets and manage risks. The newly combined
business is referred to as PG&E Integrated Energy and Marketing (PG&E Energy),
and PG&E Interstate Pipeline Operations (PG&E Pipeline). PG&E Energy is
comprised of PG&E Generating Company, LLC and its subsidiaries and PG&E Energy
Trading Holdings Corporation, which owns PG&E Energy Trading-Power, L.P. and
PG&E Energy Trading Gas-Corporation and other affiliates. PG&E Pipeline is
comprised of PG&E Gas Transmission Corporation and its subsidiaries
(collectively PG&E GTC), which includes PG&E Gas Transmission, Northwest
Corporation and its subsidiaries (collectively PG&E GTN). Other subsidiaries of
PG&E GTC, PG&E Gas Transmission, Texas Corporation and its subsidiaries and PG&E
Gas Transmission Teco, Inc and its subsidiaries (collectively PG&E GTT), through
which PG&E NEG conducted its Texas natural gas and natural gas liquids business,
were sold during the fourth quarter of 2000. Also during 2000, PG&E NEG sold its
energy
34
services unit, PG&E Energy Services Corporation.
Segment information for the three and nine months ended September 30, 2001 and
2000 was as follows:
PG&E National Energy Group
--------------------------------------------------
PG&E
Corpora-
tion &
Integrated Interstate NEG Other
Total Energy & Pipeline Elimi- Elimi-
(in millions) Utility NEG Marketing Operations nations nations/(2)/ Total
------- ------- --------- ---------- ------- ------- ----------
Three months ended September 30, 2001
Operating revenues $ 2,934 3,364 $ 3,326 $ 46 $ (8) $ - $ 6,298
Intersegment revenues /(1)/ 3 (3) (14) 11 - - -
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues 2,937 3,361 3,312 57 (8) - 6,298
Net income (loss) 737 77 64 19 (6) (43) 771
Three months ended September 30, 2000 /(4)/
Operating revenues 2,519 4,983 4,671 310 2 - 7,502
Intersegment revenues /(1)/ 4 29 17 12 - (33) -
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues 2,523 5,012 4,688 322 2 (33) 7,502
Income (loss) from continuing operations 211 43 25 16 2 (10) 244
Net income (loss) 211 24 25 16 (17) (10) 225
Nine months ended September 30, 2001
Operating revenues 7,799 10,182 10,029 157 (4) - 17,981
Intersegment revenues /(1)/ 9 138 109 29 - (147) -
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues 7,808 10,320 10,138 186 (4) (147) 17,981
Net income (loss) 433 202 152 57 (7) (65) 570
Total assets at September 30, 2001 /(3)/ 24,790 9,785 8,447 1,198 140 217 34,792
Nine months ended September 30, 2000 /(4)/
Operating revenues 7,026 11,115 10,265 847 3 - 18,141
Intersegment revenues/(1)/ 11 84 47 37 - (95) -
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues 7,037 11,199 10,312 884 3 (95) 18,141
Income (loss) from continuing operations 655 127 81 43 3 (10) 772
Net income (loss) 655 108 81 43 (16) (10) 753
Total assets at September 30, 2000 /(3)/ $ 24,183 10,853 $ 8,424 $ 2,124 $ 305 $ (419) $ 34,617
(1) Inter-segment electric and gas revenues are recorded at market prices,
which for the Utility and PG&E Pipeline are tariffed rates prescribed by
the CPUC and the FERC, respectively.
(2) Includes PG&E Corporation, Pacific Venture Capital, and elimination
entries.
(3) Assets of PG&E Corporation are included in "PG&E Corporation & Other
Eliminations" column exclusive of investment in its subsidiaries.
(4) Segment information for the prior year has been restated for comparative
purposes as required by SFAS No. 131.
35
NOTE 10: REVISION FOOTNOTE
Subsequent to the issuance of PG&E Corporation's December 31, 2000, March 31,
2001, June 30, 2001, and September 30, 2001 Consolidated Financial Statements,
management determined that the assets and liabilities relating to certain leases
should have been consolidated. The facilities associated with the leases were
under construction during 1999, 2000, and 2001. A summary of the significant
effects of the revisions to the Condensed Statements of Consolidated Operations,
Condensed Consolidated Balance Sheets, and Condensed Consolidated Statements of
Cash Flows are as follows:
As Previously As Previously
(in millions) Reported As Revised Reported As Restated
-------------------------------------------------------------
Three months ended September 30,
-------------------------------------------------------------
2001 2000
-------------------------------------------------------------
Condensed Statements of Consolidated Operations:
Total Operating Revenues $ 6,301 $ 6,298 $ 7,504 $ 7,502
Total Operating Expenses 4,749 4,746 6,875 6,873
Nine months ended September 30,
-------------------------------------------------------------
2001 2000
-------------------------------------------------------------
Total Operating Revenues $ 17,989 $ 17,981 $ 18,150 $ 18,141
Total Operating Expenses 16,330 16,322 16,223 16,214
Balance at
-------------------------------------------------------------
September 30, 2001 December 31, 2000
-------------------------------------------------------------
Condensed Consolidated Balance Sheets:
Cash and cash equivalents $ 976 $ 1,020 $ 899 $ 925
Accounts Receivable - Customers 3,047 3,046 4,342 4,340
Prepaid expenses and other 239 240 406 406
Property, plant and equipment - Construction work-in-
progress 983 2,054 900 1,605
Other non-current assets 3,181 3,181 2,398 2,530
Total Assets 33,677 34,792 35,291 36,152
Accounts payable - Trade creditors 1,177 1,226 5,856 5,896
Other current liabilities 1,554 1,560 1,563 1,570
Long-term debt 6,589 7,649 4,736 5,550
Nine months ended September 30,
-------------------------------------------------------------
2001 2000
-------------------------------------------------------------
Condensed Consolidated Statements of Cash Flows:
Accounts receivable $ 1,295 $ 1,294 $ (810) $ (813)
Accounts payable 866 875 1,294 1,342
Other - net 157 155 28 30
Capital Expenditures (1,584) (1,818) (1,220) (1,691)
Long-term debt issued 2,334 2,580 57 615
Cash and cash equivalents at September 30 976 1,020 304 329
Cash paid for interest (net of amounts capitalized) 367 421 471 487
36
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), delivers
electric service to approximately 4.6 million customers and natural gas service
to approximately 3.8 million customers. On April 6, 2001, the Utility filed a
voluntary petition for relief under Chapter 11 of the United States Bankruptcy
Code (Bankruptcy Code) in the United States Bankruptcy Court for the Northern
District of California (Bankruptcy Court). Under Chapter 11, the Utility retains
control of its assets and is authorized to operate its business as a
debtor-in-possession while being subject to the jurisdiction of the Bankruptcy
Court. On September 20, 2001, the Utility and PG&E Corporation jointly filed
with the Bankruptcy Court a proposed plan of reorganization (the Plan) of the
Utility under Chapter 11 of the Bankruptcy Code and their proposed disclosure
statement describing the Plan. The factors causing the Utility to take this
action are discussed in this Management's Discussion and Analysis (MD&A) and in
Notes 2 and 3 of the Notes to the Condensed Consolidated Financial Statements.
PG&E Corporation's subsidiary, PG&E National Energy Group, Inc. (PG&E NEG) is an
integrated energy company with a strategic focus on power generation, power
plant development, natural gas transmission and wholesale energy marketing and
trading in North America. PG&E NEG has integrated its generation, development
and energy marketing and trading activities to increase the returns from its
operations, identify and capitalize on opportunities to increase its generating
and pipeline capacity, create energy products in response to dynamic markets and
manage risks. The newly combined business is referred to as PG&E Integrated
Energy and Marketing (PG&E Energy), and PG&E Interstate Pipeline Operations
(PG&E Pipeline.) PG&E Energy is comprised of PG&E Generating Company, LLC and
its subsidiaries and PG&E Energy Trading Holdings Corporation, which owns PG&E
Energy Trading-Power, L.P. and PG&E Energy Trading Gas-Corporation and other
affiliates. PG&E Pipeline is comprised of PG&E Gas Transmission Corporation and
its subsidiaries (collectively PG&E GTC), which includes PG&E Gas Transmission,
Northwest Corporation and its subsidiaries (collectively PG&E GTN). Other
subsidiaries of PG&E GTC, PG&E Gas Transmission, Texas Corporation and its
subsidiaries and PG&E Gas Transmission Teco, Inc. and its subsidiaries
(collectively PG&E GTT), through which PG&E NEG operated its Texas natural gas
and natural gas liquids business, were sold during the fourth quarter of 2000.
Also during 2000, PG&E NEG sold its energy services unit, PG&E Energy Services
Corporation.
This is a combined Quarterly Report on Form 10-Q/A of PG&E Corporation and the
Utility. 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. This 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 PG&E Corporation's and the
Utility's consolidated financial statements and Notes to the Consolidated
Financial Statements incorporated by reference in their combined 2000 Annual
Report on Form 10-Q/A.
Subsequent to the issuance of PG&E Corporation's 2000 and 1999 consolidated
financial statements and unaudited report for the quarterly period ended
September 30, 2001, management determined that the assets and liabilities
relating to certain leases should have been consolidated. The facilities
associated with the leases were under construction during 2001 (see Note 10).
This combined Quarterly Report on Form 10-Q/A, including this MD&A, contains
forward-looking statements, including statements regarding management's guidance
regarding earnings per share and future growth, that are necessarily subject to
37
various risks and uncertainties. PG&E Corporation continues to expect that its
net income from operations for 2001 will be in the range of $2.70 to $2.75 per
share. Management also expects that earnings per share from operations will grow
by 8% to 10% in 2002. Earnings from operations exclude items impacting
comparability and should not be considered an alternative to net income or an
indicator of a Company's operating performance. 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. Although PG&E Corporation and the Utility are not able to predict
all of the factors that may affect future results, some of the factors that
could cause future results to differ materially from those expressed or implied
by the forward-looking statements, or historical results include:
. the outcome of the Utility's regulatory proceedings, including the
2001 Attrition Rate Adjustment application, the retained generation
ratemaking proceeding, the 1999 General Rate Case (GRC), and the
succeeding GRC for the test year 2003;
. whether and to what extent the Utility is determined to be responsible
for the California Independent System Operator's (ISO) charges billed
to the Utility;
. the extent to which the California Department of Water Resources'
(DWR) revenue requirement is allocated to the Utility and the impact
such allocation may have on the Utility's financial condition and
results of operation;
. the pace of the Bankruptcy Court proceedings and the effect on PG&E
Corporation and PG&E NEG;
. whether the Utility's proposed plan of reorganization is confirmed by
the Bankruptcy Court and becomes effective;
. the regulatory, judicial, or legislative actions (including ballot
initiatives) that may be taken to meet future power needs in
California, mitigate the higher wholesale power prices, provide
refunds for prior power costs, or address the Utility's financial
condition;
. the extent to which the Utility's under-collected wholesale power
purchase costs may be collected from customers;
. any changes in the amount of transition costs the Utility is allowed
to collect from its customers, and the timing of the completion of the
Utility's transition cost recovery;
. future market prices for electricity and future fuel prices, which in
part are influenced by future weather conditions, the availability of
hydroelectric power, and the development of competitive markets;
. the amount and timing of valuation of, and future ratemaking for, the
Utility's hydroelectric and other non-nuclear generation assets;
. future operating performance at the Diablo Canyon Nuclear Power Plant
(Diablo Canyon), and the future ratemaking applicable to Diablo
Canyon;
38
. legislative or regulatory changes, including the pace and extent of
the ongoing restructuring of the electric and natural gas industries
across the United States;
. future sales levels, general economic and financial market conditions,
and;
. the extent to which our current or planned generation, pipeline, and
storage capacity development projects of PG&E NEG are completed and
the pace and cost of such completion; including the extent to which
commercial operations of these development projects are delayed or
prevented because of various development and construction risks such
as PG&E NEG's failure to obtain necessary permits or equipment, the
failure of third-party contractors to perform their contractual
obligations, the failure of equipment to perform as anticipated, or an
inability to obtain equipment or labor on acceptable terms;
. the extent and timing of generating, pipeline, and storage capacity
expansion and retirement by others;
. illiquidity in the commodity energy market and PG&E NEG's ability to
provide the credit enhancements necessary to support its trading
activities;
. the extent to which unfavorable conditions in the general economy, the
energy markets or equity markets affect PG&E NEG's ability to obtain
capital for its planned development projects and future acquisitions
on acceptable terms while preserving PG&E NEG's credit quality;
. restrictions imposed upon PG&E NEG under certain term loans of PG&E
Corporation;
. fluctuations in commodity gas, natural gas liquids, and electric
prices, and the ability to successfully manage such price
fluctuations;
. the effect of compliance with existing and future environmental laws,
regulations, and policies, the cost of which could be significant; and
. the outcome of pending litigation.
As the ultimate impact of these and other factors is uncertain, these and other
factors may cause future earnings to differ materially from results or outcomes
we currently seek or expect. Each of these factors is discussed in greater
detail in this MD&A.
LIQUIDITY AND FINANCIAL RESOURCES
Utility
The California energy crisis described in Note 2 of the Notes to the Condensed
Consolidated Financial Statements has had a significant negative impact on the
liquidity and financial resources of the Utility. Beginning in June 2000, the
wholesale price of electric power in California steadily increased to an average
cost of $0.182 per kilowatt-hour (kWh) for the seven-month period June 2000
through December 2000, as compared to an average cost of $0.042 per kWh for the
same period in 1999. Under California Assembly Bill (AB) 1890, the Utility's
39
electric rates were frozen at levels that allowed approximately $0.054 per kWh
to be charged to the Utility's customers as reimbursement for power costs
incurred by the Utility on behalf of its retail customers. The excess of
wholesale electricity costs above the generation-related cost component
available in frozen rates resulted in an under-collection at December 31, 2000,
of approximately $6.6 billion.
The difference between the actual costs incurred to purchase power and the
amount recovered from customers was funded through a series of borrowings during
the last quarter of 2000.
On January 16 and 17, 2001, the outstanding bonds of the Utility were downgraded
to below-investment grade status. This downgrade to below investment grade
status was an event of default under one of the Utility's revolving credit
facilities and precluded the Utility from additional access to the capital
markets. As a result, the banks stopped funding under the revolving credit
facility. On January 17, 2001, the Utility began to default on maturing
commercial paper obligations. In addition, the Utility was no longer able to
meet its obligations to generators, qualifying facilities (QFs), the ISO, and
the Power Exchange (PX), and began making partial payments of amounts owed.
After the downgrade, the PX notified the Utility that the ratings downgrade
required the Utility to post collateral for all transactions in the PX day-ahead
market. Since the Utility was unable to post such collateral, the PX suspended
the Utility's trading privileges effective January 19, 2001, in the day-ahead
market. The PX also sought to liquidate the Utility's block-forward contracts
for the purchase of power. In February 2001, California Governor Gray Davis,
acting under California's Emergency Services Act, commandeered the contracts
valued at $243 million for the benefit of the State. The Utility, the PX, and
some of the PX market participants have filed administrative claims and state
court litigation against the State to recover the value of the seized contracts.
The administrative claims, as well as the state court litigation, are pending.
On January 19, 2001, the Utility was no longer able to continue purchasing power
for its customers because of lack of creditworthiness and the State of
California authorized the DWR to purchase electricity for the Utility's
customers. AB 1X was passed on February 1, 2001, authorizing the DWR to enter
into contracts for the purchase and sale of electric power and to issue revenue
bonds to finance electricity purchases. The DWR has entered into long-term
contracts with several generators for the supply of electricity. However, it
continues to purchase amounts of power on the spot market at prevailing market
prices.
In response to the growing crisis, on January 4, 2001, the California Public
Utilities Commission (CPUC) approved an interim energy procurement rate increase
of $0.01 per kWh. In addition, on March 27, 2001, the CPUC authorized an
additional average rate increase in retail rates of $0.03 per kWh to pay future
procurement costs.
As previously stated, beginning in June 2000, the wholesale costs of the
electricity purchased from the PX and the ISO on behalf of the Utility's retail
customers escalated. The Utility believes that since it has not met the
creditworthiness standards under the ISO's tariff since early January 2001, the
Utility should not be responsible for the ISO's purchases made to meet the
Utility's net open position. (The net open position is the amount of power
needed by retail electric customers that cannot be met by utility-owned
generation or power under contract to the utilities.) On February 14, 2001, the
Federal Energy Regulatory Commission (FERC) ordered that the ISO could buy power
only on behalf of creditworthy entities. The FERC order also stated that the ISO
could continue to schedule power for the Utility as long as it comes from its
own generation units and is routed over its own transmission lines. Despite the
FERC orders, the ISO continued to bill the Utility for the ISO's wholesale power
purchases. On April 6, 2001, the FERC issued a further order directing the ISO
40
to implement its prior order, which the FERC clarified, applies to all
third-party transactions whether scheduled or not. In light of the FERC's April
6, 2001 order, the Utility has not recorded any such estimated ISO charges after
April 6, 2001 except for the ISO's grid management charge, although the Utility
has accrued the full amount of the ISO charges up to April 6, 2001 in the
accompanying financial statements. On June 13, 2001, the FERC denied the ISO's
request for rehearing of its April 6, 2001 order.
The Utility filed a complaint in Bankruptcy Court against the ISO to prohibit
the ISO from continuing to bill the Utility for the ISO's wholesale power
purchases, unless and until the Utility is permitted to recover the costs of
such power purchases through retail electric rates. On June 26, 2001, the
Bankruptcy Court issued a preliminary injunction prohibiting the ISO from
charging the Utility for the ISO's wholesale power purchases made in violation
of bankruptcy law, the ISO's tariff, and the FERC's February 14 and April 6,
2001 orders. In issuing the injunction, the Bankruptcy Court noted that the FERC
orders permit the ISO to schedule transactions that involve either a
creditworthy buyer or a creditworthy counter-party, but noted the existence of
unresolved issues regarding how to ensure these creditworthiness requirements
for real-time transactions and emergency dispatch orders issued by the ISO to
power sellers.
As a result of the failure of the DWR to assume the full procurement
responsibility for the Utility's net open position, as was provided under AB 1X,
the negative impact of the CPUC decision that created new payment obligations
for the Utility and undermined its ability to return to financial viability, a
lack of progress in negotiations with the State of California to provide a
solution for the energy crisis, and the adoption by the CPUC of an illegal and
retroactive accounting change that would appear to eliminate the Utility's true
under-collected purchased power costs, the Utility filed a voluntary petition
for relief under provisions of the Bankruptcy Code on April 6, 2001.
Under Chapter 11, the Utility retains control of its assets and is authorized to
operate its business as a debtor-in-possession while being subject to the
jurisdiction of the Bankruptcy Court. Subsidiaries of the Utility, including
PG&E Funding LLC (which holds Rate Reduction Bonds) and PG&E Holdings LLC (which
holds stock of the Utility), are not included in the Utility's petition. The
Utility's Consolidated Financial Statements have been prepared in accordance
with the American Institute of Certified Public Accountants' Statement of
Position 90-7 (SOP 90-7), "Financial Reporting by Entities in Reorganization
Under the Bankruptcy Code," and on a going concern basis, which contemplates
continuity of operation, realization of assets and liquidation of liabilities in
the ordinary course of business. However, as a result of the filing, such
realization of assets, and liquidation of liabilities are subject to
uncertainty.
Certain claims against the Utility in existence prior to the filing of the
petition for relief are stayed while the Utility continues business operations
as a debtor-in-possession. The Utility's estimate of the valid claims is
reflected in the September 30, 2001, Condensed Consolidated Balance Sheets as
Liabilities Subject to Compromise. Additional claims (Liabilities Subject to
Compromise) may arise subsequent to the filing date resulting from (1)
negotiations, (2) rejection of executory contracts, including leases, (3)
actions by the Bankruptcy Court, (4) further developments with respect to
disputed claims, (5) proofs of claim, or (6) other events. Payment terms for
these amounts will be established through the bankruptcy proceedings. Claims
secured against the Utility's assets (secured claims) also are stayed, although
the holders of such claims have the right to move the court for relief from the
stay. Secured claims are secured primarily by liens on substantially all of the
Utility's assets. The Bankruptcy Court has approved making the regular interest
payments on the Utility's secured debt and by pledged accounts receivable from
gas customers.
The Bankruptcy Court has appointed an Official Unsecured Creditors' Committee
41
(Committee). In accordance with the provisions of the Bankruptcy Code, the
Committee has the right to be heard on all matters that come before the
Bankruptcy Court.
Since the filing, the Bankruptcy Court has approved various requests by the
Utility to permit the Utility to carry on its normal business operations, and
pay certain pre-petition obligations. Additionally, the Utility has secured
approval to spend approximately $1.5 billion in capital expenditures for ongoing
business needs such as upgrading and improving transmission lines and
substations. The Utility's current actions are intended to allow the Utility to
continue to operate while the bankruptcy proceedings continue.
On September 20, 2001, the Utility and PG&E Corporation, jointly filed with the
Bankruptcy Court a proposed plan of reorganization (the Plan) of the Utility
under the Bankruptcy Code and their proposed disclosure statement describing the
Plan (see Note 3 for a description of the Plan). On October 2, 2001, the Utility
filed with the Bankruptcy Court the Support Agreement between the Utility and
the Committee under which the Committee has agreed to support the Plan under the
conditions specified in the agreement. The Bankruptcy Court must find that the
disclosure statement contains adequate information to make an informed judgment
in voting to accept or reject the Plan. The Bankruptcy Court has set a hearing
date of December 19, 2001, to consider the adequacy of the disclosure statement.
Upon Bankruptcy Court approval, the disclosure statement will be sent to holders
of claims against, and equity interests in, the Utility in connection with the
solicitation of acceptances of the Plan. Bankruptcy Court approval of the
disclosure statement does not constitute a determination by the Bankruptcy Court
as to the merits of the Plan or an indication that the Bankruptcy Court will
confirm the Plan.
Whether the Plan becomes effective and whether the Plan is implemented in
accordance with management's projections and assumptions, are necessarily
subject to various risks and uncertainties that could cause actual results to
differ materially from those contemplated by management. Some of the factors
that could affect the outcome materially include: the pace of the Bankruptcy
Court proceedings; the extent to which the Plan is amended or modified; risks
relating to the issuance of new debt securities by each of the disaggregated
entities, including higher interest rates than are assumed in the financial
projections which could affect the amount of cash raised to satisfy allowed
claims, and the inability to successfully market the debt securities due to,
among other reasons, an adverse change in market conditions or in the condition
of the disaggregated entities before completion of the offerings; whether the
Bankruptcy Court exercises its authority to pre-empt relevant non-bankruptcy law
and if so, whether and the extent to which such assertion of jurisdiction is
successfully challenged; whether a favorable tax ruling or opinion is obtained
regarding the tax-free nature of the Internal Restructuring and the Spin-Off (as
such terms are defined in Note 3 of the Notes to the Consolidated Financial
Statements); and the ability of the Utility to successfully disaggregate its
businesses.
The filing for bankruptcy protection and the related uncertainty around the plan
of reorganization that is ultimately adopted will have a significant impact on
the Utility's future liquidity and results of operations. The Utility is not
able at this time to predict the outcome of its bankruptcy case, or the effect
of the Chapter 11 reorganization process on the claims of the creditors of the
Utility or the interests of the Utility's preferred security holders. However,
the Utility believes, based on information presently available to it, that cash
available from operations will provide sufficient liquidity to allow it to
continue as a going concern for the foreseeable future.
42
PG&E Corporation
The liquidity and financial condition crisis faced by the Utility also
negatively impacted PG&E Corporation. Through December 31, 2000, PG&E
Corporation funded its working capital needs primarily by drawing down on
available lines of credit and other short-term credit facilities. At December
31, 2000, PG&E Corporation had borrowed $185 million against its five-year
revolving credit agreement and had issued $746 million of commercial paper. Due
to the credit ratings downgrades of PG&E Corporation, the banks refused any
additional borrowing requests and terminated their remaining commitments under
existing credit facilities. Commencing January 17, 2001, PG&E Corporation began
to default on its maturing commercial paper obligations.
On March 2, 2001, PG&E Corporation refinanced its debt obligations with $1
billion in aggregate proceeds of two term loans under a common credit agreement
with General Electric Capital Corporation and Lehman Commercial Paper Inc. In
accordance with the credit agreement, the proceeds, together with other PG&E
Corporation cash, were used to pay $501 million in commercial paper (including
$457 million of commercial paper on which PG&E Corporation had defaulted), $434
million in borrowings under PG&E Corporation's long-term revolving credit
facility, and $109 million to PG&E Corporation shareholders of record as of
December 15, 2000, in satisfaction of a defaulted fourth quarter 2000 dividend.
Further, approximately $99 million was used to pre-pay the first year's interest
under the credit agreement and to pay transaction expenses associated with the
debt restructuring.
PG&E Corporation itself had cash and short-term investments of $256 million at
September 30, 2001, and believes that the funds will be adequate to maintain
PG&E Corporation's continuing operations through 2002. In addition, PG&E
Corporation believes that the holding company and its non-CPUC regulated
subsidiaries are protected from the bankruptcy of the Utility.
PG&E NEG
General
Historically, PG&E NEG has obtained cash from operations, borrowings under
credit facilities, non-recourse project financing and other issuances of debt,
issuances of commercial paper, and borrowings and capital contributions from
PG&E Corporation. These funds have been used to finance operations, service debt
obligations, fund the acquisition, development, and/or construction of
generating facilities, start up other businesses, finance capital expenditures,
and meet other cash and liquidity needs.
The projects that PG&E NEG develops typically require substantial capital. To
date, PG&E NEG has made a number of commitments associated with the planned
growth of owned and controlled generating facilities, as well as pipelines.
These include commitments for projects under construction, commitments for the
acquisition and maintenance of equipment needed for projects under development,
payment commitments for tolling arrangements, and forward sale and purchase
commitments associated with PG&E NEG's energy marketing and trading activities.
On May 22, 2001, PG&E NEG completed an offering of $1 billion in senior
unsecured notes and received net proceeds after bond discount of approximately
$972 million. PG&E NEG used a portion of the proceeds and intends to use the
balance of the senior notes issuance, net of $28 million of debt discount and
note issuance costs, to pay down existing revolving debt, fund investments in
generating facilities and pipeline assets, working capital requirements, and
other general corporate requirements. These senior notes have an aggregate
43
principal amount of $1 billion, bear interest at 10.375% per annum, and mature
on May 16, 2011.
In addition, PG&E Corporation historically has provided to PG&E NEG credit
support for a range of contractual commitments. With respect to generating
facilities, this credit support has included agreements to infuse equity in
specific projects when these projects begin operations or when a project that
has been leased is purchased. PG&E Corporation also has provided guarantees of
PG&E NEG obligations under several long-term tolling arrangements and as
collateral for commitments under various energy trading contracts entered into
by its energy trading operations to provide short-term collateral to
counter-parties. As of September 30, 2001, except for $8 million of guarantees
relating to various energy trading master contracts, all PG&E Corporation equity
infusion agreements and guarantees have been replaced with PG&E NEG equity
infusion agreements, guarantees, or other forms of security.
In connection with the replacement of PG&E Corporation guarantees with PG&E NEG
guarantees, and with the continued growth of energy trading and marketing
positions, PG&E NEG has experienced a substantial increase in the need for
various liquidity facilities to provide letters of credit and cash deposits with
various counter-parties. On June 15, 2001, PG&E NEG established a $550 million
revolving credit facility (which includes the ability to issue letters of
credit) with a syndicate of banks to support PG&E NEG's energy trading
operations and other working capital requirements. The $550 million revolving
credit facility was subsequently increased to $1.25 billion on August 23, 2001.
On September 30, 2001, $156 million of letters of credit, and $295 million in
borrowings were outstanding under this facility.
Generating Projects in Development
PG&E NEG has reviewed its growth plans for its electric generating business in
light of circumstances presented by recent changes in energy and equity markets
as well as the slowdown of the U.S. economy. Further, energy prices and
price-earnings multiples for competitive energy companies have significantly
declined, thereby constraining access to equity funds at acceptable terms to
PG&E NEG. In response to these market changes, PG&E NEG continues to assess and
modify its growth plans for ownership and control of electric generating
facilities to manage its future capital and equity requirements. As a result,
based on PG&E NEG's view of the regional energy markets, PG&E NEG expects to
delay, swap or sell generation development projects that are currently not under
construction and associated commitments to take delivery of turbines. Management
expects that PG&E NEG's total owned and controlled generating capacity will be
less than the 22,000 megawatts in 2004 that had been previously forecast. Since
management's review of its growth plans for ownership and control of electric
generating facilities is ongoing, it is not practical to provide new projections
of the total capacity that PG&E NEG will own or control.
Further, PG&E Corporation has previously stated that it expects PG&E NEG to
contribute 30% to consolidated earnings per share from operations by the end of
2002. Given the current circumstances of the energy and equity markets as
discussed above, management does not expect that this goal can be achieved.
Nevertheless, management expects that PG&E NEG will contribute roughly 20% to
25% to consolidated earnings from operations in 2001 and that it will contribute
roughly the same percentage in 2002.
STATEMENTS OF CASH FLOWS
PG&E Corporation normally funds investing activities from cash provided by
operations after capital requirements, and to the extent necessary, external
44
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. However, the Utility is
currently operating as a debtor-in-possession under Chapter 11 of the Bankruptcy
Code. While certain pre-petition debts are stayed, the Utility does not have
access to external funding from the capital markets.
PG&E Corporation Consolidated
Net cash provided by PG&E Corporation's operating activities totaled $1,799
million and $1,257 million for the nine months ended September 30, 2001 and
2000, respectively. The increase of $542 million between 2001 and 2000 is
attributable to the volatility caused by the California energy crisis previously
discussed.
Cash Flows from Investing Activities
------------------------------------
Cash used in investing activities was $2,053 million during the nine months
ended September 30, 2001, compared with $2,014 million used during the same
period for 2000. In 2001, the primary use of cash for investing activities was
$1,818 million for additions to property, plant, and equipment, compared with
$1,691 million used for similar purposes in 2000.
Cash Flows from Financing Activities
------------------------------------
Cash generated through financing activities was $349 million and $804 million
for the nine months ended September 30, 2001, and 2000, respectively. A loan in
2001 netted $906 million in proceeds which together with cash on hand and from
operating activities, were used to repay defaulted commercial paper, other
loans, and the $109 million in dividends. The $804 million provided by financing
activities in 2000 resulted from increased borrowings of $894 million offset by
a dividend payment of $325 million.
Utility
The following section discusses the Utility's significant cash flows from
operating, investing, and financing activities for the nine-month periods ended
September 30, 2001 and 2000.
Cash Flows from Operating Activities
------------------------------------
Net cash provided by the Utility's operating activities totaled $1,279 million
and $1,297 million for the nine months ended September 30, 2001 and 2000,
respectively. The decrease of $18 million between 2001 and 2000 is primarily
attributable to higher cost of gas, offset by partial payment of pre-petition
obligations.
Cash Flows from Investing Activities
-------------------------------------
The primary uses of cash for investing activities are additions to property,
45
plant, and equipment. The Utility's capital expenditures for the nine months
ended September 30, 2001, were $889 million.
Cash Flows from Financing Activities
------------------------------------
During the nine months ended September 30, 2001, the Utility did not declare any
preferred or common stock dividends, compared with a payment of dividends on its
common and preferred stock of $375 million for the nine months ended September
30, 2000. The Utility has suspended payment of its common and preferred
dividends due to its financial condition. Dividends on preferred stock are
cumulative. Until cumulative dividends on preferred stock are paid, the Utility
may not pay any dividends on its common stock to, or repurchase its common stock
from, PG&E Corporation and PG&E Holdings, LLC.
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during the nine months ended September 30, 2001, totaled $325
million. Of this amount, $213 million related to the Utility's rate reduction
bonds maturing, $93 million related to mortgage bonds maturing, and $19 million
related to the maturities and redemption of various Utility medium-term notes
and other debt.
The Utility maintained a $1 billion credit facility, which was due to expire in
November 2002. The unused portion of this facility was cancelled by the
bank-lending group on January 23, 2001, citing the event of default on
non-payment of a material amount of debt. This facility was previously used to
support the Utility's commercial paper program and other liquidity requirements.
At September 30, 2001, the Utility had drawn, and had outstanding $938 million
under this facility to repay maturing commercial paper. In addition, the total
defaulted commercial paper outstanding at September 30, 2001, formerly backed by
both this and another now-cancelled facility, was $873 million.
There was no new long-term debt issued in the nine-month period ended September
30, 2001. In addition, there was no additional commercial paper issued during
this same period.
As of November 1, 2001, the Utility is current with all interest and sinking
fund payments on its mortgage bonds.
Due to the bankruptcy filing, the Utility is unable at this time to repay
unsecured pre-petition creditors. The Utility has not made interest payments on
the following unsecured debt: medium-term notes, pollution control loan
agreements, the 7.375% senior notes, the $1.24 billion floating rate notes,
commercial paper, bank loans, or other unsecured debt. The Utility has not made
principal payments on $1,242 million of unsecured debt that matured from July
2001 through October 2001.
The Utility is accruing interest on all unpaid debt obligations and compounding
interest at interest rates described in the Plan.
The Utility is in default under the credit provider's reimbursement agreements,
and consequently four credit providers have declared $454 million of the
pollution control loan agreements due and payable. The redemptions were funded
by drawdowns on the letters of credit. Interest payments are current on the
remaining $814 million pollution control loan agreements.
The Utility received notice from the trustee of the Cumulative Quarterly Income
Preferred Securities (QUIPS) that the Utility's bankruptcy filing was an event
of default under the trust agreement and that the trustee will take steps to
liquidate the trust and distribute the 7.90% deferrable interest subordinated
46
debentures to bondholders. As of September 30, 2001, the Company Obligated
Mandatorily Redeemable Preferred Securities of Trust Holding Solely Utility
Subordinated Debentures have been reclassified to liabilities subject to
compromise on the Condensed Consolidated Balance Sheets.
PG&E NEG
The following section discusses PG&E NEG's significant cash flows from
operating, investing, and financing activities for the nine-month period ended
September 30, 2001 and 2000.
Cash Flows from Operating Activities
------------------------------------
During the nine months ended September 30, 2001, PG&E NEG generated net cash of
$334 million in operating activities. Net cash from operating activities before
changes in other working capital accounts was $149 million, primarily driven by
increased net income. Net cash inflow related to certain other working capital
accounts was $185 million, driven primarily by deliveries of previously held
forward positions in trading.
Cash Flows from Investing Activities
------------------------------------
During the nine months ended September 30, 2001, PG&E NEG used net cash of
$1,165 million in investing activities. PG&E NEG's cash outflows from investing
activities were primarily attributable to capital expenditures on generating
projects in construction, turbine prepayments, and advanced development of
generating capacity.
Cash Flows from Financing Activities
------------------------------------
Net cash generated by financing activities was $837 million for the nine months
ended September 30, 2001 principally from the net proceeds related to the senior
notes.
RESULTS OF OPERATIONS
The table shows for the three- and nine-months ended September 30, 2001 and
2000, certain items from the Condensed Consolidated Statements of Operations
detailed by Utility and PG&E NEG operations of PG&E Corporation. (In the "Total"
column, the table shows the combined results of operations for this group.) The
information for PG&E Corporation (the "Total" column) includes the appropriate
intercompany elimination. Following this table we discuss our results of
operations.
47
PG&E National Energy Group
-------------------------------------------------------
PG&E
Corpora-
tion &
Integrated Interstate NEG Other
Total Energy & Pipeline Elimi- Elimi-
Utility NEG Marketing Operations nations nations/(1)/ Total
---------- -------- ------------- ----------- --------- ------------- -------
(in millions)
Three months ended September 30,
2001
Operating revenues $ 2,937 $ 3,361 $ 3,312 $ 57 $ (8) $ - $ 6,298
Operating expenses 1,509 3,225 3,205 28 (8) 12 4,746
Operating income 1,552
Reorganization interest income 32
Interest income 29
Interest expense (317)
Other income (expenses), net (38)
Income taxes 487
Net income 771
Net cash provided by operating
activities 1,070
Net cash used by investing
activities (836)
Net cash provided by financing
activities 60
EBITDA/(2)/ 1,639 177 132 42 3 (32) 1,784
Three months ended September 30,
2000/3/
Operating revenues 2,523 5,012 4,688 322 2 (33) 7,502
Operating expenses 1,990 4,919 4,646 272 1 (36) 6,873
Operating income 629
Interest income 59
Interest expense (191)
Other income (expenses), net (14)
Income taxes 239
Income from continuing operations 244
Net income 225
Net cash used by operating
activities (475)
Net cash used by investing
activities (1,030)
Net cash provided by financing
activities 1,511
EBITDA/(2)/ (446) 104 68 54 (18) 22 (320)
Nine months ended September 30,
2001
Operating revenues 7,808 10,320 10,138 186 (4) (147) 17,981
Operating expenses 6,464 9,974 9,897 80 (3) (116) 16,322
Operating income 1,659
Reorganization interest income 64
Interest income 106
Interest expense (876)
Other income (expenses), net (43)
Income taxes 340
Net income 570
Net cash provided by operating
activities 1,799
Net cash used by investing
activities (2,053)
Net cash provided by financing
activities 349
EBITDA/(2)/ 1,976 468 324 141 3 (44) 2,400
Nine months ended September 30,
2000
Operating revenues 7,037 11,199 10,312 884 3 (95) 18,141
Operating expenses 5,382 10,914 10,180 732 2 (82) 16,214
Operating income 1,927
Interest income 109
Interest expense (556)
Other income (expenses), net (37)
Income taxes 671
Income from continuing operations 772
Net income 753
Net cash provided by operating
activities 1,257
Net cash used by investing
activities (2,014)
Net cash provided by financing
activities 804
EBITDA/(2)/ $ 1,006 $ 357 $ 205 $ 170 $ (18) $ 6 $ 1,369
48
/(1)/ Net income on inter-company positions recognized by segments using
mark-to-market accounting is eliminated. Inter-company transactions are
also eliminated.
/(2)/ EBITDA is defined as income before provision for income taxes, interest
expense, interest income, depreciation, and amortization. EBITA is not
intended to represent cash flows from operations and should not be
considered as an alternative to net income as an indicator of PG&E
Corporation's operating performance or to cash flows as a measure of
liquidity. Refer to the Statement of Cash Flows for the U.S. GAAP basis
cash flows. PG&E Corporation believes that EBITDA is a standard measure
commonly reported and widely used by analysts, investors, and other
interested parties. However, EBITDA as presented herein may not be
comparable to similarly titled measures reported by other companies.
/(3)/ Segment information for the prior period has been restated to conform
with new segment presentation (see Note 9 of the Notes to the Condensed
Consolidated Financial Statements).
49
Overall Results
PG&E Corporation's financial position and results of operations continue to be
impacted by the California energy crisis. Please see the Liquidity and Financial
Resources section and Notes 2 and 3 of the Notes to the Condensed Consolidated
Financial Statements for more information on the California energy crisis.
PG&E Corporation's net income for the third quarter ended September 30, 2001,
was $771 million, compared to net income of $225 million for the same period in
2000, representing an increase of $546 million. The Utility's net income
available for common stock for the quarter ended September 30, 2001, accounted
for $526 million of the increase.
PG&E Corporation's net income for the nine-month period ended September 30,
2001, was $570 million compared to net income of $753 million for the same
period in 2000. Of the $183 million net decrease from the prior nine-month
period in 2000, the Utility was responsible for virtually all of the decrease,
somewhat offset by a $94 million increase in net income at PG&E NEG.
Subject to final resolution of regulatory and judicial matters, PG&E Corporation
and the Utility expect future earnings to continue to reflect increased
volatility as a result of no longer being able to reflect the impact of
generation-related regulatory balancing accounts in their financial statements.
As previously discussed, the Utility cannot meet the accounting probability
standard required to defer generation costs for future recovery. As such, costs
and revenues historically deferred in regulatory balancing accounts now directly
impact net income. The Utility's net income will be impacted by changes in
electricity and gas costs, customer demand, weather, costs of operations,
conservation, and other related items.
The changes in performance for the three- and nine-month periods ended September
30, 2001 and 2000 are generally attributable to the following factors:
.. Due to the lack of a regulatory, legislative, or judicial solution to the
California energy crisis, the Utility cannot defer for future recovery its
under-collected purchased power costs. These costs have been expensed as
incurred, and as a result the Utility's earnings were affected. Beginning
in June 2001, the Utility began collecting revenues associated with the
CPUC's March 27, 2001 interim energy procurement surcharges. As a result,
the Utility's generation-related component of its electric revenues was
greater than its generation-related costs. This differential resulted in an
increase to earnings of $687 million in the third quarter of 2001, and $124
million year-to-date. In addition, for the nine-month period ended
September 30, 2001, revenues include $327 million (after-tax) related to
the market value of certain terminated bilateral contracts.
.. As a result of the liquidity crisis attributable to the California energy
crisis, PG&E Corporation has significantly increased its borrowings and
unpaid debts accruing interest. Additionally, the effective interest rate
paid on these new borrowings has also increased because of the higher risk
associated with PG&E Corporation's financial position. The incremental cost
of these borrowings was $62 million, after-tax, for the quarter ended
September 30, 2001, and $165 million, after-tax, for the nine-month period
ended September 30, 2001.
.. The Utility's filing of a petition of reorganization under Chapter 11 of
the Bankruptcy Code has resulted in incremental expenses associated with
the development of a plan of reorganization. For the quarter ended
September 30, 2001, these fees and expenses amounted to approximately $25
million after-tax. For the nine-month period ended September 30, 2001,
total incremental expenses
50
were approximately $50 million after-tax.
.. During the three-month period ending September 30, 2001, the Utility
incurred losses of approximately $66 million after-tax associated with the
involuntary termination of gas transportation hedges caused by a decline in
the Utility's credit rating.
.. During the third quarter of 2001, the CPUC issued two decisions modifying
its previous decision in the Utility's 1999 General Rate Case. The first,
to correct a tax computation error, had the impact of adding approximately
$33 million to net income (approximately $24 million related to 1999 and
2000) and the second modification had the impact of decreasing net income
by approximately $21 million of which $15 million related to 1999 and 2000.
.. PG&E NEG increased earnings by $56 million for the three-month period ended
September 30, 2001, over the same period in 2000. For the nine-month period
ended September 30, 2001, earnings increased by $94 million as compared to
the same period in 2000. This increase was the result of higher gross
margins at the wholesale energy business, the sale of a development
project, and a lower effective federal tax rate. In addition, a $19 million
loss on discontinued operations was recorded in the third quarter of 2000,
which had a favorable impact on the comparative results for the three- and
nine-month periods ended September 30, 2001.
Dividends
PG&E Corporation's historical quarterly common stock dividend was $0.30 per
common share, which corresponded to an annualized dividend of $1.20 per common
share.
On January 10, 2001, the Board of Directors of PG&E Corporation suspended the
payment of its fourth quarter 2000 common stock dividend of $0.30 per share
declared by the Board of Directors on October 18, 2000, and payable on January
15, 2001, to shareholders of record as of December 15, 2000. The California
energy crisis had created a liquidity crisis for PG&E Corporation, which led to
the suspension of payments of dividends to conserve cash resources. These
defaulted dividends were later paid on March 2, 2001, in conjunction with the
refinancing of PG&E Corporation obligations, discussed above under the Liquidity
and Financial Resources section.
Additionally, the parent company refinancing agreements mentioned above prohibit
dividends from being declared or paid until the term loans have been repaid. The
agreement is for a term of two years with an option on behalf of PG&E
Corporation to extend the term for an additional year.
On January 10, 2001, the Utility suspended the payment of its fourth quarter
2000 common stock dividend of $110 million, declared in October 2000, to PG&E
Corporation and the Utility's wholly owned subsidiary PG&E Holdings, LLC. Until
its financial condition is restored, the Utility is precluded from paying
dividends to PG&E Corporation and PG&E Holdings, LLC.
51
Utility
Overall Results
---------------
The Utility's income available for common stock was $737 million for the quarter
ended September 30, 2001, compared to $211 million for the same period in 2000.
This increase in income of $526 million, or 249%, was primarily the result of
increased generation-related electric operating revenues no longer subject to
balancing account deferrals and decreased depreciation, amortization, and
decommissioning expenses associated with previously written-off
generation-related transition costs. The increased income was reduced somewhat
by increased interest expenses and costs associated with the bankruptcy.
The Utility's income available for common stock was $433 million for the
nine-month period ended September 30, 2001, compared to $655 million for the
same period in 2000. This decrease in income of $222 million is primarily
attributable to the increased cost of electric energy partially offset by
decreased depreciation, amortization, and decommissioning expenses associated
with generation-related transition costs previously written-off, and increased
interest expense and costs associated with the bankruptcy.
Operating Income
----------------
The Utility's operating income was $1,428 million for the quarter ended
September 30, 2001, compared to operating income of $533 million for the same
period in 2000. This increase in operating income is primarily attributable to
the increase in generation-related electric revenues no longer subject to
balancing account deferrals as well as lower depreciation expenses during the
period as a result of the write-off taken in December 2000.
The Utility's operating income was $1,344 million for the nine months ended
September 30, 2001, compared to operating income of $1,655 million for the same
period in 2000. This decrease in operating income is primarily due to decreased
electric revenues, and increased cost of electric energy partially offset by
decreased depreciation, amortization, and decommissioning expenses, as a result
of the write-off taken in December 2000.
Operating Revenues
------------------
The Utility's operating revenues for the quarter ended September 30, 2001, were
$2,937 million in 2001, and $2,523 million in 2000, an increase of 16%. Electric
revenues increased by $510 million, or 26%, for the quarter ended September 30,
2001, primarily due to the interim energy procurement surcharges, which were
levied in 2001. Historically, these revenues would have been recorded in a
balancing account and applied against transition costs. Those costs were
written-off in 2000 and all generation-related revenues and costs are recognized
as incurred. The total surcharges billed for the third quarter of 2001 were
approximately $1 billion, but were reduced by approximately $645 million of
revenues collected for electricity provided to the Utility's customers by DWR.
52
Revenues collected on behalf of the DWR and the related costs are not reflected
in the Utility's Condensed Consolidated Statements of Operations as the Utility
is a collection agent for the DWR. In addition, electric revenues increased
because of lower direct access credits and partially offset by customer
conservation.
The Utility's gas revenues decreased $96 million for the quarter ended September
30, 2001, compared with the same period in 2000 due to customer conservation
efforts and decreased usage by retail customers resulting from milder weather
conditions.
The Utility's operating revenues for the nine-month period ended September 30,
2001, were $7,808 million compared to operating revenues of $7,037 million for
the same period in 2000. The increase of $771 million, or 11%, is due to the
increase in gas revenues of $907 million and decrease in electric revenues of
$136 million for the nine-month period ended September 30, 2001, compared with
the same period in 2000, respectively. The increase in gas revenues was
primarily due to higher average costs of gas, which are passed on directly to
retail customers.
The decrease in electric revenues was primarily the result of the reduction to
revenue resulting from a portion of the Utility's billed revenues being passed
through directly to the DWR for the DWR's electricity purchases. This reduction
was largely offset by increased revenues from energy procurement and the 2001
interim energy procurement surcharges. Revenues increased by $1.5 billion for
the surcharges billed but were reduced by $1.8 billion of revenue collected for
electricity provided to the Utility's customer by the DWR. In addition, revenues
decreased because the Utility experienced lower usage due to customer
conservation efforts offset by lower direct access credits.
In accordance with CPUC regulations, the Utility provides an energy credit to
those customers (known as direct access customers) who have chosen to buy their
electric generation energy from an energy service provider (ESP) other than the
Utility. The Utility bills direct access customers based upon fully bundled
rates (generation, distribution, transmission, public purpose programs, and a
competition transition charge). However, the direct access customer receives an
energy credit equal to the average generation price multiplied by customer
energy usage for the period.
For the nine-month period ended September 30, 2001, the estimated total of
accumulated credits for direct access customers is approximately $368 million.
Such amounts are reflected on the Utility's Condensed Consolidated Balance
Sheet. The actual amount that will be refunded to ESPs or directly to the
customer will be dependent upon the outcome of the Utility's bankruptcy
proceeding, when the rate freeze ends, and whether there are any adjustments
made to wholesale energy prices by the FERC.
53
Operating Expenses
------------------
The table below summarizes the changes in the Utility's operating expenses:
Three months ended Percentage
September 30, Increase Increase
----------------------
2001 2000 (Decrease) (Decrease)
---------- ---------- ------------ ------------
Operating Expenses
Cost of electric energy $ 434 $ 2,056 $ (1,622) (79)%
Deferred electric procurement costs - (2,176) 2,176 -
Cost of gas 263 178 85 48
Operating and maintenance 563 730 (167) (23)
Depreciation, amortization, and decommissioning 224 1,202 (978) (81)
Reorganization professional fees and expenses 25 - 25 -
---------- ---------- ------------
Total operating expenses $ 1,509 $ 1,990 $ (481) (24)%
========== ========== ============
Nine months ended Percentage
September 30, Increase Increase
----------------------
2001 2000 (Decrease) (Decrease)
---------- ---------- ------------ ------------
Operating Expenses
Cost of electric energy $ 2,389 $ 3,544 $ (1,155) (33)%
Deferred electric procurement costs - (2,789) 2,789 -
Cost of gas 1,608 643 965 150
Operating and maintenance 1,771 1,824 (53) (3)
Depreciation, amortization, and decommissioning 663 2,160 (1,497) (69)
Reorganization professional fees and expenses 33 - 33 -
---------- ---------- ------------
Total operating expenses $ 6,464 $ 5,382 $ 1,082 20%
========== ========== ============
The cost of electric energy decreased by $1,622 million for the quarter ended
September 30, 2001, compared to the same period in 2000 due to wholesale
electricity purchases made by the DWR for the Utility's net short position in
2001, which are not reflected in the Utility's financial statements, and due to
the lower average cost of electricity in 2001. The average cost was $0.18 per
kWh in the summer of 2000, compared with $0.10 per kWh in the summer of 2001.
The cost of electric energy decreased by $1,155 million for the nine-month
period ended September 30, 2001, compared to the same period in 2000. This was
due to wholesale electricity purchases made by the DWR for the Utility's net
open position in 2001, which are not reflected in the Utility's financial
statements, and due to the lower average cost of electricity in 2001 compared
with 2000. The average cost in 2001 decreased by approximately $0.08 per kWh,
compared with the 2000 average cost. In addition, there was a statewide energy
conservation campaign in effect, and cooler summer weather throughout the region
in the third quarter of this year, which moderated customers' usage, compared
with the same period last year.
For the three- and nine-month periods ended September 30, 2000,
generation-related costs of $2.1 billion and $2.8 billion, respectively, were
deferred and subsequently written off at December 31, 2000.
54
The cost of gas increased by $85 million for the quarter ended September 30,
2001 due to losses associated with the involuntary termination of gas
transportation hedges caused by a decline in the Utility's credit rating.
The cost of gas increased by $965 million for the nine-month period ended
September 30, 2001, compared to the same period in 2000. The average cost of gas
was $6.38 per decatherm (DTh) for the nine-month period ended September 30,
2001, compared to $2.93 per DTh for the same period in the prior year. The
procurement costs for gas are passed directly to the customers.
The Utility's operating and maintenance expenses decreased $167 million for the
quarter ended September 30, 2001, and decreased $53 million for the nine-month
period ended September 30, 2001, compared to the same periods in 2000. The
decrease of $167 million is primarily attributable to the impact in 2000 of an
unscheduled 10-day outage at Diablo Canyon with no such outage in 2001, and the
decrease in other generation-related costs
Depreciation, amortization, and decommissioning decreased by $978 million for
the quarter ended September 30, 2001, and $1,497 million for the nine-month
period ended September 30, 2001, compared to the same periods in 2000. These
decreases were the result of the lower depreciation expenses due to last year's
accelerated amortization of generation-related assets and the write-off of
generation-related transition costs in December 2000.
Dividends
The Utility has suspended payment of its common and preferred dividends.
Dividends on preferred stock are cumulative. Until cumulative dividends on
preferred stock are paid, the Utility may not pay any dividends on its common
stock to, or repurchase its common stock from, PG&E Corporation and PG&E
Holdings, LLC.
PG&E NEG
Operating Income
-----------------
Operating income at PG&E NEG was $136 million for the third quarter ended
September 30, 2001, compared to $93 million for the same period in 2000. For the
nine-month period ended September 30, 2001, operating income was $346 million,
compared to $285 million for the same period in 2000.
Operating Revenues
-----------------
Operating revenues were $3.4 billion in the three months ended September 30,
2001, a decrease of $1.7 billion, or 33%, from the three months ended September
30, 2000. This decline in operating revenues occurred principally in the
wholesale energy trading business with a decrease of $1.4 billion primarily due
to a decline in volume and realized prices in the third quarter of 2001 as
compared to the same period last year. In the pipeline segment, the decline in
operating revenues of $265 million is primarily due to the sale of PG&E GTT in
December 2000.
55
Operating revenues were $10.3 billion in the nine months ended September 30,
2001, a decrease of $879 million, or 8%, from the nine months ended September
30, 2000. This decline in operating revenues occurred principally in the
wholesale energy trading business mainly due to a decline in volume and realized
prices, primarily in the third quarter of 2001, as compared to the prior year.
In the pipeline segment, the decline in operating revenues of $698 million is
primarily due to the sale of PG&E GTT in December 2000.
Operating Expenses
------------------
Operating expenses were $3.2 billion in the three months ended September 30,
2001, a decrease of $1.7 billion, or 34%, from the three months ended September
30, 2000. This decline in operating expenses occurred principally in the
wholesale energy trading business with a decrease of $1.4 billion due to a
decline in volume and realized prices in the third quarter of 2001 as compared
to the same period last year. In the pipeline segment, the decline in operating
expenses of $244 million is primarily due to the sale of PG&E GTT in December
2000.
Operating expenses were $10 billion in the nine months ended September 30, 2001,
a decrease of $940 million, or 9%, from the nine months ended September 30,
2000. This decline in operating expenses occurred principally in the wholesale
energy trading business mainly due to a decline in volume and realized prices,
primarily in the third quarter of 2001, as compared to the prior year. In the
pipeline segment, the decline in operating expenses of $652 million is primarily
due to the sale of PG&E GTT in December 2000.
Dividends
PG&E NEG currently intends to retain any future earnings to fund the development
and growth of its business. Further, PG&E NEG is precluded from paying dividends
unless it meets certain financial tests. Therefore, it is not anticipating
paying any cash dividends on its common stock in the foreseeable future.
REGULATORY MATTERS
A significant portion of PG&E Corporation's operations is 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. The Utility's significant regulatory proceedings are discussed below.
Regulatory proceedings associated with electric industry restructuring are
discussed above in "The California Energy Crisis" (see Note 2 of the Notes to
the Condensed Consolidated Financial Statements).
The Utility's 1999 GRC
The CPUC authorizes an amount known as "base revenues" to be collected from
ratepayers to recover the Utility's basic business and operational costs for its
gas and electric distribution operations. Base revenues, which include
non-fuel-related operating and maintenance costs, depreciation, taxes, and a
return on invested capital, currently are authorized by the CPUC in GRC
proceedings.
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On October 16, 2001, the CPUC issued a decision, voted on at the CPUC's October
10, 2001 meeting, granting applications for rehearing that had been filed by The
Utility Reform Network (TURN) and another party with respect to the CPUC's
February 17, 2000 decision in the Utility's 1999 GRC for the period 1999 to
2001. As previously disclosed, the applications for rehearing which had been
pending since March 2000, alleged that the CPUC committed legal error by
approving funding in certain areas that were not adequately supported by record
evidence.
In the decision, the CPUC found that in proposing a general rate increase, the
Utility has the obligation to produce clear and convincing evidence for each
component of its proposed revenue requirements, and the CPUC cannot grant the
requested increase to the extent the Utility fails to meet that obligation. In
the rehearing decision, the CPUC reversed in part its prior determination
regarding the adequacy of the evidence supporting the original 1999 GRC decision
and reduced the adopted electric and gas distribution annual revenue requirement
by approximately $40 million.
In addition, the decision orders the record to be reopened to receive evidence
of the actual level of 1998 electric distribution capital spending in relation
to the forecast used to determine 1999 rates, possibly resulting in an
adjustment of the adopted 1998 forecast level to conform to the 1998 recorded
level.
Following the 1998 capital spending rehearing and resolution of all other
outstanding matters, a final Results of Operations analysis will be performed,
and a final revenue requirement will be determined. The decision apparently
intends that the revised revenue requirement would be made retroactive to
January 1, 1999.
The Utility is evaluating further CPUC and judicial review options. A petition
for review of the rehearing decision by the California Supreme Court or the
Court of Appeal would be filed by November 14, 2001.
The Utility's 2002 GRC
As previously disclosed, the procedural schedule in the Utility's 2002 GRC,
which would determine revenue requirements for the period 2002 through 2005, has
been delayed. On October 25, 2001, the CPUC issued a decision requiring the
Utility to file a 2003 test year GRC (rather than a 2002 test year) by November
14, 2001. The CPUC stated that its goal is to have new rates "in place" by
January 1, 2003.
In the order, the CPUC requested that the Utility and others file comments by
November 9, 2001 on whether the Utility needs a 2002 attrition rate adjustment
(ARA) as compared to rates authorized in the Utility's 1999 GRC. The Utility
intends to file comments stating the need for a 2002 ARA increase.
The Utility's Retained Generation Ratemaking Proceeding
In June 2001, the Utility filed its proposed ratemaking for retained utility
generation facilities and procurement costs still incurred by the Utility. The
Utility's proposal requested that the ratemaking for its retained generating
facilities be set in accordance with previous and still effective CPUC decisions
under AB 1890. Under Public Utilities Code (PUC) Section 377, as amended in
January 2001, utilities are prohibited from divesting their retained generating
plants before January 1, 2006. However, PUC Section 377 as amended does not
modify or repeal PUC Section 367, which still requires the CPUC to market value
the generating assets of each utility by no later than December 31, 2001 based
on appraisal, sale, or other divestiture. Under the CPUC's previous AB 1890
decisions, the market valuation of the Utility's retained non-nuclear generating
57
facilities is to be used to pay off transition costs. The Utility believes it is
entitled to recover whatever market value is credited against transition cost
recovery. Further, the ratemaking for the Utility's Diablo Canyon is based on a
specific "benefit sharing" formula established in a 1997 CPUC decision.
On October 25, 2001, the CPUC issued a decision denying the Utility's request
that the market value of its retained utility generating facilities be used to
establish prospective ratemaking for those facilities in the CPUC's retained
generation proceeding. The CPUC said its decision did not address how to treat
past uneconomic costs incurred by the Utility and that when issues concerning
the termination of the rate freeze are resolved, the CPUC should address any
impacts on ratemaking for the Utility's retained generation. Although hearings
were concluded in July 2001, the CPUC has not yet issued a proposed decision
establishing the Utility's retained generation revenue requirement. Once a
proposed decision is issued, the Utility will have a chance to comment on it
before the CPUC issues the final decision.
Order Instituting Investigation into Holding Company Activities
On April 3, 2001, the CPUC issued an order instituting an investigation (OII)
into whether the California investor-owned utilities, including the Utility,
have complied with past CPUC decisions, rules, or orders authorizing their
holding company formations and/or governing affiliate transactions, as well as
applicable statutes. The order states that the CPUC will investigate (1) the
Utilities' transfer of money to their holding companies since deregulation of
the electric industry commenced, including during times when their utility
subsidiaries were experiencing financial difficulties, (2) the failure of the
holding companies to financially assist the utilities when needed, (3) the
transfer by the holding companies of assets to unregulated subsidiaries, and (4)
the holding companies' action to "ringfence" their unregulated subsidiaries. The
CPUC will also determine whether additional rules, conditions, or changes are
needed to adequately protect ratepayers and the public from dangers of abuse
stemming from the holding company structure. The CPUC will investigate whether
it should modify, change, or add conditions to the holding company decisions,
make further changes to the holding company structure, alter the standards under
which the CPUC determines whether to authorize the formation of holding
companies, otherwise modify the decisions, or recommend statutory changes to the
California Legislature. As a result of the investigation, the CPUC may impose
remedies (including penalties), prospective rules, or conditions, as
appropriate.
PG&E Corporation and the Utility believe that they have complied with applicable
statutes, CPUC decisions, rules, and orders. As described above, on April 6,
2001, the Utility filed a voluntary petition for relief under Chapter 11 of the
Bankruptcy Code. PG&E Corporation and the Utility believe that to the extent the
CPUC seeks to investigate past conduct for compliance purposes, the
investigation is automatically stayed by the bankruptcy filing. Neither the
Utility nor PG&E Corporation can predict what the outcome of the investigation
will be or whether the outcome will have a material adverse effect on their
results of operations or financial condition. On April 13, 2001, the Utility
filed an application for rehearing of the classification of the OII as
quasi-legislative, arguing that the issues of compliance, violations, and
remedies for past violations must be reclassified as adjudicatory.
On May 14, 2001, the CPUC issued an interim decision that recategorized the
proceeding from quasi-legislative to the ratesetting category because the
ratesetting category is most appropriate for mixed factual and policy
proceedings. In addition, the CPUC noted that the proceeding may be
recategorized as adjudicatory at a later time if the CPUC finds that the Utility
violated prior decisions and other laws. On June 14, 2001, the CPUC denied the
Utility's request for rehearing of the interim decision placing this proceeding
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in the ratesetting category.
The Utility's 2001 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.
The increase reflects inflation and the growth in capital investments necessary
to serve customers. The Utility did not request an increase in gas distribution
revenues. In December 2000, the CPUC issued an interim order finding that a
decision on the application could not be rendered by January 1, 2001, and
determining that if attrition relief is eventually granted, that relief will be
effective as of January 1, 2001. This matter was heard and briefed in June,
July, and August 2001. During the course of hearings, the Utility reduced its
requested electric rate increase to $185 million. Although the CPUC's Office of
Ratepayer Advocates and one other party recommended that the Utility's request
be denied on policy grounds, the Utility believes that their recommendations are
unreasonable and that the Utility's request for an electric revenue increase is
fully justified by the record in this proceeding. The ALJ has issued a draft
decision authorizing an increase in electric distribution revenues of
approximately $151 million, effective January 1, 2001. The matter is currently
scheduled to be considered at the CPUC's December 11, 2001 decision conference.
The Utility's Cost of Capital Proceedings
Each year, the Utility files an application with the CPUC to determine the
authorized rate of return that the Utility may earn on its electric and gas
distribution assets and recover from ratepayers. Since February 17, 2000, the
Utility's adopted return on common equity (ROE) has been 11.22% on electric and
gas distribution operations, resulting in an authorized 9.12% overall rate of
return (ROR). The Utility's earlier adopted ROE was 10.6%. 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 an
ROE of 12.4%, and an overall ROR of 9.75%. 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% long-term debt,
5.8% preferred stock, and 48% common equity. In March 2001, the CPUC issued a
proposed decision recommending no change to the current 11.22% ROE for test year
2001. This authorized ROE results in a corresponding 9.12% return on rate base
and no change in the Utility's electric or gas revenue requirement for 2001. A
final CPUC decision is pending.
The Utility's FERC Transmission Rate Cases
Electric transmission revenues, and both wholesale and retail transmission rates
are subject to authorization by the FERC. The FERC has not yet acted upon a
settlement filed by the Utility that, if approved, would allow the Utility to
recover $391 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. A FERC order approving this settlement
is expected by the end of 2001. The Utility has accrued $29 million for
potential refunds related to the 14-month period ended May 31, 1999. In April
2000, the FERC approved a settlement that permits the Utility to recover $298
59
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. Further,
in July 2001, the FERC approved another settlement that permits the Utility to
collect $251 million annually in electric transmission rates beginning on May 6,
2001. This decrease in transmission rates relative to previous time periods is
due to unusually large balances paid to the Utility from the ISO for congestion
management charges and other transmission related services billed by the ISO.
In March 2001, the Utility filed at FERC to increase its power and transmission
related rates to the Western Area Power Administration (Western). The majority
of the requested increase is related to passing through market power prices
billed to the Utility by the ISO and others for services, which apply to Western
under a pre-existing contract between the Utility and Western. On September 21,
2001, the FERC Administrative Law Judge (ALJ) issued an Initial Decision denying
the Utility the ability to increase the rates as requested. On October 24, 2001,
the FERC confirmed the ALJ Initial Decision in its entirety. Pending any
decision by the Utility to appeal the FERC decision, until December 31, 2004,
the date the Western contract expires, Western's rates will continue to be
calculated on a yearly basis pursuant to the formula specified in Western's
contact. Any revenue shortfall resulting from these rates is collectible as a
retail customer stranded cost.
The Utility's Gas Accord II Application
On October 9, 2001, the Utility filed a Gas Accord II Application with the CPUC,
requesting a two-year extension, without modification, of the existing Gas
Accord. This filing was made in response to a recent CPUC order, which directed
the Utility to file a Gas Accord II application.
Under the Utility's proposal, those provisions of the Gas Accord currently
scheduled to expire on January 1, 2003, will be extended through December 31,
2004, while certain storage-related provisions scheduled to expire on April 1,
2003 will be extended through March 31, 2005. No change in the previously
approved rates in effect as of December 2002 or, in the case of certain storage
provisions, as of March 31, 2003, is proposed. The Utility believes the two-year
extension that has been proposed will allow for resolution of many uncertainties
affecting gas markets today, including the Utility's proposed plan of
reorganization.
The Utility's Federal Lawsuit
On November 8, 2000, the Utility filed a lawsuit in federal district court in
San Francisco against the CPUC Commissioners. The Utility asked the court to
declare that the federally approved wholesale electricity costs the Utility has
incurred to serve its customers are recoverable in retail rates both before and
after the end of the transition period. The lawsuit stated that the wholesale
power costs the Utility has incurred are paid pursuant to filed rates, which the
FERC has authorized and approved, and that under the United States Constitution
and numerous federal court decisions, state regulators cannot disallow such
costs. The Utility's lawsuit also alleged that to the extent that the Utility is
denied recovery of these mandated wholesale electricity costs by order of the
CPUC, such action constitutes an unlawful taking and confiscation of the
Utility's property.
On May 2, 2001, the court dismissed the Utility's complaint, without prejudice
to refile the lawsuit at a later time, on the ground that the suit was premature
since two of the challenged CPUC decisions were not yet final. On August 6,
2001, the Utility refiled its complaint in the United States District Court for
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the Northern District of California, based on the fact that the CPUC's decisions
referenced in the Court's order had become final under California law. The CPUC
and TURN filed motions to dismiss the complaint. The previously scheduled
hearing date for the motions of November 7, 2001, has been postponed by the
court and a new hearing date has not been set.
ENVIRONMENTAL MATTERS
PG&E Corporation and the Utility are subject to laws and regulations established
to both maintain and improve the quality of the environment. Where PG&E
Corporation's and the Utility's properties contain hazardous substances, these
laws and regulations require PG&E Corporation and the Utility to remove those
substances or remedy effects on the environment. See Note 8 of the Notes to the
Consolidated Financial Statements for further discussion of environmental
matters.
Utility
The Utility records an environmental remediation 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.
At September 30, 2001, the Utility expects to spend $319 million, undiscounted,
for hazardous waste remediation costs at identified sites, including divested
fossil-fueled power plants. The cost of the hazardous substance remediation
ultimately undertaken by the Utility is difficult to estimate. A change in the
estimate may occur in the near term due to uncertainty concerning the Utility's
responsibility, the complexity of environmental laws and regulations, and the
selection of compliance alternatives. If 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 could spend as much as $471 million on these
costs. The Utility estimates the upper limit of the range using assumptions
least favorable to the Utility, based upon a range of reasonably possible
outcomes. Costs may be higher if the Utility is found to be responsible for
clean-up costs at additional sites or expected outcomes change.
The Utility had an environmental remediation liability of $319 million and $320
million at September 30, 2001, and December 31, 2000, respectively. The $319
million accrued at September 30, 2001, includes (1) $139 million related to the
pre-closing remediation liability, associated with divested generation
facilities, and (2) $180 million related to remediation costs for those
generation facilities that the Utility still owns, manufactured gas plant sites,
and gas gathering compressor stations. Of the $319 million environmental
remediation liability, the Utility has recovered $193 million through rates, and
expects to recover another $109 million in future rates. The Utility also is
recovering its costs from insurance carriers and from other third parties as
appropriate.
On June 28, 2001, the Bankruptcy Court entered its "Order on Debtor's Motion for
Authority to Continue Its Hazardous Substances Cleanup Program." The Utility is
61
authorized to expend (i) up to $22 million in each calendar year in which the
Chapter 11 case is pending to continue its hazardous substance remediation
programs and procedures, and (ii) any additional amounts necessary in emergency
situations involving post-petition releases or threatened releases of hazardous
substances, if such excess expenditures are necessary in the Utility's
reasonable business judgment to prevent imminent harm to public health and
safety or the environment (provided that the Utility seeks the Court's approval
of such emergency expenditures at the earliest practicable time), in each case
as described in the Utility's motion.
The California Attorney General, on behalf of various state environmental
agencies, filed proofs of claims in the Utility's bankruptcy proceeding for
environmental claims aggregating to approximately $770 million. For most if not
all of these sites, the Utility is in the process of remediation in cooperation
with the relevant agencies or would be so in the future in the normal course of
business. In addition, for the majority of the remediation claims, the state
would not be entitled to recover these costs unless they accept responsibility
to clean up the sites, which is unlikely. Since the Plan provides that the
Utility intends to respond to these types of claims in the regular course of
business, and since the Utility has not argued that the bankruptcy proceeding
relieves the Utility of its obligations to respond to valid environmental
remediation orders, the Utility believes the claims seeking specific cash
recoveries are invalid.
In December 1999, the Utility was notified by the purchaser of its former Moss
Landing power plant that it had identified a cleaning procedure used at the
plant that released heated water from the intake, and that this procedure is not
specified in the plant's National Pollutant Discharge Elimination System (NPDES)
permit issued by the Central Coast Regional Water Quality Control Board (Central
Coast Board). The purchaser notified the Central Coast Board of its findings. In
March 2000, the Central Coast Board requested the Utility to provide specific
information regarding the "backflush" procedure used at Moss Landing. The
Utility provided the requested information to the Board in April 2000. The
Utility's investigation indicated that while it owned Moss Landing, significant
amounts of water were discharged from the cooling water intake. While the
Utility's investigation did not clearly indicate that discharged waters had a
temperature higher than ambient receiving water, the Utility believes that the
temperature of the discharged water was higher than that of the ambient
receiving water. In December 2000, the executive officer of the Central Coast
Board made a settlement proposal to the Utility under which the Utility would
pay $10 million, a portion of which would be used for environmental projects and
the balance of which would constitute civil penalties. A proof of claim has been
filed by the California Attorney General in the Utility's bankruptcy proceeding
on behalf of the Central Coast Board seeking unspecified penalties for alleged
discharges of heated cooling water from Moss Landing. Settlement negotiations
are continuing.
The Utility's Diablo Canyon employs a "once through" cooling water system, which
is regulated under a NPDES Permit, issued by the Central Coast Board. This
permit allows Diablo Canyon to discharge the cooling water at a temperature no
more than 22 degrees above ambient receiving water and requires that the
beneficial uses of the water be protected. The beneficial uses of water in this
region include industrial water supply, marine and wildlife habitat, shellfish
harvesting, and preservation of rare and endangered species. In January 2000,
the Central Coast Board issued a proposed draft Cease and Desist Order (CDO)
alleging that, although the temperature limit has never been exceeded, Diablo
Canyon's discharge was not protective of beneficial uses. In October 2000, the
Central Coast Board and the Utility reached a tentative settlement of this
matter pursuant to which the Central Coast Board has agreed to find that the
Utility's discharge of cooling water from the Diablo Canyon plant protects
beneficial uses and that the intake technology reflects "best technology
available" under Section 316(b) of the Federal Clean Water Act. As part of the
settlement, the Utility will take measures to preserve certain acreage north of
the plant and will fund
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approximately $5 million in environmental projects related to coastal resources.
The parties are negotiating the documentation of the settlement. The final
agreement will be subject to public comment and will be incorporated in a
consent decree to be entered in California Superior Court. A claim has been
filed by the California Attorney General in the Utility's bankruptcy proceeding
on behalf of the Central Coast Board seeking unspecified penalties and other
relief in connection with the Diablo Canyon's operation of its cooling water
system.
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 NEG
In May 2000, PG&E NEG received an Information Request from the U.S.
Environmental Protection Agency (EPA), pursuant to Section 114 of the Federal
Clean Air Act (CAA). The Information Request asked PG&E NEG to provide certain
information, relative to the compliance of the Brayton Point and Salem Harbor
Generating Stations with the CAA. No enforcement action has been brought by the
EPA to date. PG&E NEG has had very preliminary discussions with the EPA to
explore a potential settlement of this matter. As a result of this and related
regulatory initiatives by the Commonwealth of Massachusetts, PG&E NEG is
exploring initiatives that would assist it to achieve significant reductions of
sulfur dioxide and nitrogen oxide emissions by as early as 2006 to 2010. PG&E
NEG believes that it would meet these requirements through installation of
controls at the Brayton Point and Salem Harbor plants and estimates that capital
expenditures on these environmental projects will be approximately $265 million
through 2006. PG&E NEG believes that it is not possible to predict at this point
whether any such settlement will occur or in the absence of a settlement the
likelihood of whether the EPA will bring an enforcement action.
GenLLC's existing power plants, including USGen New England, Inc. (USGenNE)
facilities, are subject to federal and state water quality standards with
respect to discharge constituents and thermal effluents. Three of the
fossil-fueled plants owned and operated by USGenNE are operating pursuant to
NPDES permits that have expired. For the facilities whose NPDES permits have
expired, permit renewal applications are pending, and it is anticipated that all
three facilities will be able to continue to operate under existing terms and
conditions until new permits are issued. It is estimated that USGenNE's cost to
comply with the new permit conditions could be as much as $60 million through
2005. It is possible that the new permits may contain more stringent limitations
than prior permits.
In September 2000, PG&E NEG settled a legal claim through certain agreements
that require PG&E NEG to alter its existing wastewater treatment facilities at
its Brayton Point and Salem Harbor generating facilities. PG&E NEG began the
activities during 2000 and is expected to complete them in 2002 as the review
and permitting process with the state has caused some delays. In addition to
costs incurred in 2000, at December 31, 2000, PG&E NEG recorded a reserve in the
amount $3.2 million relating to its estimate of the remaining environmental
expenses to fulfill its obligations under the agreement. In addition, PG&E NEG
expects to incur approximately $4 million in capital expenditures during 2001
and into 2002 to complete the project.
PRICE RISK MANAGEMENT ACTIVITIES
PG&E Corporation and its subsidiaries have established risk management policies
that allow derivatives to be used for both trading and non-trading purposes (a
derivative is a contract whose value is dependent on or derived from the value
of some underlying asset). PG&E Corporation and its subsidiaries use derivatives
63
for non-trading (hedging) purposes primarily to offset our primary market risk
exposures, which include commodity price risk, interest rate risk, and foreign
currency risk. We also use derivatives, including those used for trading
(non-hedging) purposes, to participate in markets to gather market intelligence,
create liquidity, maintain a market presence, and enhance the value of our
trading portfolio. Such derivatives include forward contracts, futures, swaps,
options, and other contracts. Net open positions (that is, positions that are
either not hedged or only partially hedged) often exist due to ownership of
physical assets (such as power plants, gas pipelines, etc.) and the obligation
to serve customers. Net open positions may also be established based on the
assessment of market conditions, business objectives, and risk tolerance limits
set by management. To the extent that PG&E Corporation and its subsidiaries have
an open position, they are exposed to the risk that fluctuating commodity
prices, interest rates, and foreign currency exchange rates may adversely impact
their financial results.
PG&E Corporation and its subsidiaries may engage in the trading of derivatives
only in accordance with policies established by the PG&E Corporation Risk Policy
Committee. Trading is permitted only after the Risk Policy Committee authorizes
such activity subject to appropriate financial exposure limits. Under PG&E
Corporation, both PG&E NEG and the Utility have their own Risk Management
Committees that address matters relating to those companies' respective
businesses. These Risk Management Committees are comprised of senior officers.
Market Risk
Commodity Price Risk
Commodity price risk is the risk that changes in market prices will adversely
affect earnings and cash flows. PG&E Corporation and the Utility are primarily
exposed to the commodity price risk associated with energy commodities such as
electricity and natural gas. Therefore, PG&E Corporation's and the Utility's
strategy for reducing its commodity price risk exposure for its price risk
management activities primarily involves buying and selling fixed-price
commodity commitments into the future.
In compliance with regulatory requirements, the Utility manages price risk
independently from the activities in PG&E Corporation's unregulated business.
Because of different regulatory incentives and rate-making methods, the Utility
reports its commodity price risk separately for its electricity and natural gas
businesses. Price risk management strategies primarily consist of the use of
physical forward purchases and non-trading (hedging) financial instruments to
attain our objective of reducing the impact of commodity price fluctuations for
electricity and natural gas associated with the Utility's procurement
obligations to meet its retail electricity and natural gas loads. While the use
of these instruments has been authorized by the CPUC, the CPUC has yet to
establish rules around how it will judge the reasonableness of these instruments
for electricity purchases. Gains and losses associated with the use of the
majority of these financial instruments primarily affect regulatory accounts,
depending on the business unit and the specific program involved.
Utility Electric Commodity Price Risk
The Utility has had a very limited ability to enter into forward contracts to
hedge its exposure to commodity price fluctuations because of the reluctance of
counter-parties to extend credit. As the Utility's credit rating dropped below
investment grade in January 2001, the DWR began purchasing wholesale power for
electric customers on behalf of the state of California. In February 2001,
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because the Utility was unable to make payment to the PX for existing power
purchases, the PX sought to liquidate the Utility's remaining block-forward
contracts. Before they could do so, the PX block-forward contracts were seized
by California Governor Gray Davis for the benefit of the state, acting under
California's Emergency Services Act. As a result of continued increasing
purchased power costs in excess of revenues from customers and lack of solutions
to the energy crises, on April 6, 2001, the Utility sought protection from its
creditors through a Chapter 11 bankruptcy filing. Several counter-parties
terminated existing bilateral contracts in the first and second quarter of 2001
due to the downgrade of the Utility's credit rating and its subsequent
bankruptcy filing. As explained in Note 2 of the Notes to the Condensed
Consolidated Financial Statements, the Utility believes that it is no longer
responsible for purchases needed to meet the Utility's net open position.
Pursuant to CPUC orders, the Utility is currently paying the DWR the amount of
money it collects in retail generation rates for electricity purchased by the
DWR (that is, excluding transmission, distribution, and other revenues collected
from customers). The Utility believes that it is obligated to remit only these
revenues to the DWR, and therefore, there is no price risk for electricity
purchases to serve the net open position.
As explained in Note 3 of the Notes to the Condensed Consolidated Financial
Statements, on September 20, 2001, PG&E Corporation and the Utility filed a
proposed plan of reorganization of the Utility with the Bankruptcy Court. Upon
the effective date of the Plan, the reorganized Utility will transfer its
generation assets to the Gen entity under PG&E Corporation. Gen will operate as
an independent power producer thereafter. As an independent owner/operator, Gen
could face increased price risk associated with variability in power prices.
Additionally, the reorganized Utility could face price risk if and when it
resumes the net open position not already provided for by the DWR's contracts.
The reorganized Utility may reassume this responsibility at an unknown future
date when it regains an investment grade credit rating. Under the Plan, the
Utility requested from the Bankruptcy Court an order to prohibit it from
reassuming the net open position until objective and timely cost pass-through
and procurement pre-approval reassured. To manage this risk for both companies
and to provide a sufficiently stable framework for financing, Gen will sell its
generation output to the reorganized Utility under a power sales agreement
having a term of 12 years. As a result, during the term of the agreement, the
price risk should be limited to replacement power requirements, if any, brought
about by low hydroelectric availability and/or unit outages that may occur.
Utility Natural Gas Commodity Price Risk
Under a ratemaking method called the Core Procurement Incentive Mechanism
(CPIM), the Utility recovers in retail rates the cost of procuring natural gas
for its customers as long as the costs are within a 99% to 102% "dead-band" of a
benchmark price. The CPIM benchmark price reflects a weighting of prescribed
daily and monthly gas price indices that are representative of Utility gas
purchases. Ratepayers and shareholders share costs or savings outside the
dead-band equally. In addition, the Utility has contracts for capacity on the
Transwestern gas pipeline. There is price risk related to the Transwestern gas
pipeline to the extent that unused portions of the pipeline are brokered at
floating rates.
Under a ratemaking pact called the Gas Accord, currently scheduled to be in
effect through December 2002, shareholders are at risk for any revenues from the
sale of capacity on the Utility's pipelines and gas storage fields held by the
California Gas Transmission (CGT) business unit. The Utility is generally
exposed to reduced revenues when price spreads narrow and when throughput
volumes are lower than expected.
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PG&E NEG Commodity Price Risk
PG&E NEG is exposed to commodity price risk of its portfolio of electric
generation assets and supply contracts that serve wholesale and industrial
customers, in addition to various merchant plants currently in development. PG&E
NEG manages such risks using a cost-effective risk management program that
primarily includes the buying and selling of fixed-price commodity commitments
to lock in future cash flows of their forecasted generation. PG&E NEG is also
exposed to commodity price risk of net open positions within their trading
portfolio due to the assessment of and response to changing market conditions.
Value-at-Risk
PG&E Corporation and its subsidiaries measure commodity price 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. We quantify market risk using a variance/co-variance value-at-risk model
that 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 uses historical data for calculating the price volatility of
our contractual positions and how likely the prices of those positions will move
together. The model includes all derivatives and commodity instruments in our
trading and non-trading portfolios. PG&E Corporation and the Utility express
value-at-risk as a dollar amount of the potential loss in the fair value of our
portfolios based on a 95% confidence level using a one-day liquidation period.
Therefore, there is a 5% probability that PG&E Corporation and its subsidiaries
portfolios will incur a loss in one day greater than its value-at-risk.
The Utility's daily value-at-risk commodity price risk exposure for non-trading
activities as of September 30, 2001, was $6 million for its natural gas
business. The Utility believes that there is currently no commodity price risk
associated with fluctuating electric power prices, because the Utility is not
currently responsible for managing the net open position.
PG&E NEG's daily value-at-risk commodity price risk exposure as of September 30,
2001, was $8 million for trading activities and $19 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. Value-at-risk also does not reflect the
significant regulatory, legislative, and legal risks currently facing the
Utility due to the Utility's bankruptcy proceedings and the current California
energy crisis.
Interest Rate Risk
PG&E Corporation and the Utility are exposed to changes in interest rates
primarily as a result of their variable rate commercial paper, bonds, bank
loans, floating rate notes, project financing, and investing activities. In
addition, the Utility is exposed to changes in interest rates on interest
accruing on loan payments and trade payables currently in default. Upon
confirmation of the Plan, PG&E Corporation and the Utility plan to re-finance
existing fixed and floating
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rate debt through a fixed income offering. Prior to the pricing of this debt,
PG&E Corporation and the Utility are significantly exposed to rising interest
rates.
For a complete discussion of the risk management strategies and financial
instruments used to manage interest rate risk, see PG&E Corporation's 2000
Annual Report on Form 10-K. PG&E Corporation and the Utility use sensitivity
analysis to measure their interest rate price risk by computing estimated
changes in cash flows as a result of assumed changes in market interest rates.
As of September 30, 2001, if interest rates had averaged 1% higher, PG&E
Corporation's and the Utility's earnings would have decreased by approximately
$37 million and $34 million, respectively.
Foreign Currency Risk
PG&E Corporation and the Utility are exposed to foreign currency risk associated
with the Canadian dollar. For a complete discussion of the risk management
strategies and financial instruments used to manage foreign currency risk, see
PG&E Corporation's 2000 Annual Report on Form 10-K. PG&E Corporation and the
Utility use sensitivity analysis to measure its foreign currency exchange rate
exposure to the Canadian dollar. As of September 30, 2001, if the Canadian
dollar had experienced 10% devaluation, estimated losses would not have had a
material impact on PG&E Corporation or the Utility's Condensed Consolidated
Financial Statements.
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 8 of the Notes to
the Condensed Consolidated Financial Statements for further discussion of
significant pending legal matters.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PG&E Corporation's and Pacific Gas and Electric Company's (the Utility) primary
market risk results from changes in energy prices and interest rates. PG&E
Corporation and the Utility engage in price risk management activities for both
trading and non-trading purposes. Additionally, PG&E Corporation and the Utility
may engage in trading and non-trading activities using forwards, futures,
options, and swaps to hedge the impact of market fluctuations on energy
commodity prices, interest rates, and foreign currencies. (See Risk Management
Activities, included in Management's Discussion and Analysis above.)
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Pacific Gas and Electric Company Bankruptcy
As previously reported, on April 6, 2001, Pacific Gas and Electric Company (the
Utility) filed a voluntary petition for relief under the provisions of Chapter
11 of the United States Bankruptcy Code (Bankruptcy Code) in the United States
Bankruptcy Court for the Northern District of California (Bankruptcy Court).
Bankruptcy law imposes an automatic stay to prevent parties from making certain
claims or taking certain actions that would interfere with the estate or
property of a Chapter 11 debtor. In general, the Utility may not pay
pre-petition debts without the Bankruptcy Court's permission. Under the
Bankruptcy Code, the Utility has the right to reject or assume executory
contracts (contracts that require future performance). Since the filing, the
Bankruptcy Court has approved various requests by the Utility to permit the
Utility to carry on its normal business operations and to pay certain
pre-petition obligations. For a discussion of some of these proceedings see the
Quarterly Reports on Form 10-Q filed by PG&E Corporation and Pacific Gas and
Electric Company for the quarters ended March 31 and June 30, 2001.
On September 20, 2001, the Utility and PG&E Corporation jointly filed with the
Bankruptcy Court a proposed plan of reorganization (the Plan) and Disclosure
Statement under Chapter 11 of the U.S. Bankruptcy Code. For a description of the
Plan, see Note 3 of the Notes to the Consolidated Financial Statements in Part
I, Item 1 of this report. On October 2, 2001, the Utility filed with the
Bankruptcy Court the Support Agreement between the Utility and the Official
Unsecured Creditors' Committee under which the committee has agreed to support
the Plan under the conditions specified in the agreement.
At a status conference held on October 9, 2001, the Bankruptcy Court set the
following dates: objections to the Disclosure Statement are due November 27,
2001, a status conference will be held on December 4, 2001, and the Disclosure
Statement hearing will be held on December 19, 2001. At the October 9, 2001
status conference, the California Public Utilities Commission (CPUC) argued that
the Utility should be required to initiate adversary proceedings in the
Bankruptcy Court to decide certain legal issues before the plan confirmation
hearing. The CPUC argued that unless the Disclosure Statement described how
these legal issues were resolved, the Disclosure Statement was insufficient. The
Bankruptcy Court ordered that the CPUC and any other party submit its brief in
support of its position that adversary proceedings are required by November 6,
2001. The Utility's brief in opposition is due November 27, 2001.
Through September 5, 2001, the last day for non-governmental creditors to file
proofs of claim, non governmental claims had been submitted for an approximate
aggregate amount of $42.1 billion. This amount includes claims filed by
generators, which the Utility believes have been overstated and claims by
financial institutions, which the Utility believes contains significant
duplication. In addition, through October 3, 2001, the last day for governmental
entities to file proofs of claims, claims had been submitted by various
governmental agencies for an approximate aggregate amount of $1.9 billion. These
include, but are not limited to, contingent environmental claims, claims for
federal, state and local taxes, and claims submitted by the California
Department of Water Resources for approximately $430 million for certain energy
purchases made on behalf of the Utility's retail customers.
The claims resolution process in bankruptcy can range from estimation, which may
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involve a mini-trial held before plan confirmation to establish the amount of
claims for purposes such as voting on the Plan and the feasibility of the Plan,
and determination of the amount of the claim for distribution purposes, which
may involve a full trial. In addition, it is very common to negotiate with
creditors to achieve an agreed settlement of their claims. The Utility intends
to explore settlement of claims wherever possible and as appropriate and
necessary to pursue estimation or litigation.
Compressor Station Chromium Litigation
As described in PG&E Corporation and the Utility's Annual Report on Form 10-K
for the year ended December 31, 2000 and Quarterly Report on Form 10-Q for the
quarter ended March 31, 2001, ten cases have been pending in California courts
against the Utility. One of these suits also names PG&E Corporation as a
defendant.
On or about September 24, 2001, the Utility discovered that another complaint,
Bowers v. PG&E, was filed in Los Angeles Superior Court on April 20, 2001 on
behalf of 40 plaintiffs who allege personal injuries resulting from alleged
exposure to chromium at the Utility's gas compressor station located at
Kettleman, California. The complaint does not name PG&E Corporation and has not
yet been served on the Utility. The Utility has filed a notice of stay with the
Los Angeles Superior Court.
Further, on or about October 28, 2001, the Utility discovered that another
complaint titled Martinez v. PG&E was filed in San Bernardino Superior Court on
June 29, 2001, on behalf of four plaintiffs. The Utility has not been served.
The complaint alleges personal injuries, wrongful death, and loss of consortium,
arising from alleged exposure to chromium at the Utility's gas compressor
station located at Hinkley, California. Plaintiffs seek compensatory and
punitive damages. The complaints do not name PG&E Corporation as a defendant.
The Utility intends to file a notice of stay with the San Bernardino Superior
Court.
Including these new cases, there are now twelve cases comprising the compressor
station chromium litigation. There are now approximately 1,250 plaintiffs in
these cases. The Utility believes that all twelve cases have been stayed by the
automatic stay provisions of the Bankruptcy Code. The one case in which PG&E
Corporation has been named as a defendant remains pending.
There have been approximately 1,240 claims filed with the Bankruptcy Court in
the Utility's bankruptcy case (by most of the plaintiffs in the chromium
litigation and other individuals) alleging that exposure to chromium in soil,
air or water near the Utility's compressor stations at Kettleman, Hinkley or
Topock, California caused personal injuries, wrongful death or other injuries.
Approximately 1,050 of these claimants have filed claims for damages that total
more than $500 million. The remaining claims seek recovery for an unknown amount
of claimed damages.
PG&E Corporation and the Utility believe that, after taking into account the
reserves recorded as of December 31, 2000, the ultimate outcome of this matter
will not have a material adverse effect on their financial condition or results
of operation.
Pacific Gas and Electric Company v. California Public Utilities Commissioners
As described in PG&E Corporation's and the Utility's Annual Report on Form 10-K
for the year ended December 31, 2000 and Quarterly Report on Form 10-Q for the
quarter ended March 31, 2001, the Utility's lawsuit against the CPUC
Commissioners, asking the court to declare that the federally approved wholesale
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power costs the Utility has incurred to serve its customers are recoverable in
retail rates, was dismissed on May 2, 2001 on the grounds that the suit was
premature as the court found that two of the challenged CPUC decisions were not
then final. On August 6, 2001, the Utility re-filed its complaint in the United
States District Court for the Northern District of California, based on the fact
that the CPUC decisions referenced in the court's order had become final under
California law. The CPUC and The Utility Reform Network, a ratepayer advocacy
group, have filed motions to dismiss the complaint. The previously scheduled
hearing date for the motions of November 7, 2001 has been postponed by the
court, and no new hearing date has been set yet.
Federal Securities Lawsuit
As previously disclosed in the Quarterly Reports on Form 10-Q filed by PG&E
Corporation and the Utility for the quarters ended March 31 and June 30, 2001,
the plaintiff voluntarily dismissed the Utility from the action entitled Pacific
Gas and Electric Company, and DOES 6 to 10, Inclusive. On August 9, 2001, the
plaintiff filed a first amended complaint entitled Jack Gillam, et al. vs. PG&E
Corporation, Robert D. Glynn, Jr., and Peter A. Darbee, in the U.S. District
Court for the Northern District of California. The first amended complaint,
purportedly brought on behalf of all persons who purchased PG&E Corporation
common stock or certain shares of the Utility's preferred stock between July 20,
2000 and April 9, 2001, claims that defendants caused PG&E Corporation's
Condensed Consolidated Financial Statements for the second and third quarters of
2000 to be materially misleading in violation of federal securities laws by
recording as a deferred cost and capitalizing as a regulatory asset the
undercollections that resulted when escalating wholesale energy prices caused
the Utility to pay far more to purchase electricity than it was permitted to
collect from customers. The defendants have filed a motion to dismiss the first
amended complaint, based largely on public disclosures by PG&E Corporation, the
Utility and others regarding the undercollections, the risk that they might not
be recoverable, the financial consequences of non-recovery, and other
information from which analysts and investors could assess for themselves the
probability of recovery. The motion is scheduled to be heard on December 10,
2001.
Management believes the case is without merit and intends to present a vigorous
defense. PG&E Corporation is unable to predict whether the outcome of this
litigation will have a material adverse effect on its financial condition or
results of operations.
Moss Landing Power Plant
As previously disclosed in the Annual Report on Form 10-K filed by PG&E
Corporation and the Utility for the year ended December 31, 2000, the Utility
has been negotiating with the Central Coast Regional Water Quality Control Board
(Central Coast Board) regarding certain cleaning procedures used at the
Utility's former Moss Landing power plant that released heated water and organic
debris from the intake. A proof of claim has been filed in the Bankruptcy Court
by the California Attorney General on behalf of the Central Coast Board seeking
unspecified penalties for alleged discharges of heated cooling water at Moss
Landing. As previously reported, in December 2000 the Central Coast Board
demanded $10 million, comprised of civil penalties and environmental projects in
an unspecified ratio to settle its claim with respect to the alleged Moss
Landing discharges.
PG&E Corporation and the Utility believe that the ultimate outcome of this
matter will not have a material adverse impact on PG&E Corporation's or the
Utility's financial position or results of operations.
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In re: Natural Gas Royalties Qui Tam Litigation
This matter is a consolidation of approximately 77 False Claims Act cases that
were filed by Jack J. Gyrnberg (called a relator in the parlance of the False
Claims Act) on behalf of the United States of America, against more than 330
defendants, entitled In re: Natural Gas Royalties Qui Tam Litigation, that is
pending in the United States District Court, District of Wyoming. Two of
Grynberg's complaints named as defendants the Utility, Pacific Gas Transmission
(now PG&E Gas Transmission, Northwest Corporation (PG&E GT-NW)) and various
former PG&E Corporation entities. On October 20, 1999, these cases were
transferred to the United States District Court, District of Wyoming, along with
most of the other cases, for pretrial purposes.
Under the procedure established by the False Claims Act, a complaint is filed
under seal. While the case is under seal, the United States (acting through the
Department of Justice (DOJ)) is given an opportunity to investigate the
allegations and to intervene in the case and take over its prosecution if it
chooses to do so. Under the False Claims Act, if a case is successful, the
relator may receive a percentage of any recovery obtained on behalf of the
United States.
The current case grows out of prior litigation brought by the same relator in
1995. On April 17, 1995, Mr. Grynberg sued approximately 70 defendants (most of
which were interstate pipelines) and the Utility, in an action entitled United
------
States of America ex rel. Jack Grynberg v. Alaska Pipeline Company, et al.,
---------------------------------------------------------------------------
(Grynberg I). The United States declined to intervene in Grynberg I, and the
complaint was unsealed on March 13, 1996. The case went forward and was
prosecuted by the relator. Upon the defendants' motions, the case was dismissed
without prejudice for improper joinder of defendants and failure to plead fraud
with particularity. Grynberg appealed to the United States Court of Appeals for
the District of Columbia Circuit. In September 1998, that court summarily
affirmed the district court's decision on the ground of improper joinder.
After the district court's initial dismissal, in 1997 and 1998, the relator
filed a second wave of False Claims Act cases (Grynberg II) against the original
defendants and hundreds of additional parties in nine jurisdictions where the
defendants could be located. Approximately 77 cases were filed against more than
330 defendants, including the Utility, PG&E GT-NW, and various former PG&E
Corporation entities that were sold in December 2000. (The buyer of these
entities assumed liability for this matter as to the acquired entities.) As
discussed above, most of the Grynberg II cases were consolidated and transferred
to the United States District Court, District of Wyoming.
All of the Grynberg II complaints allege that the various defendants (most of
which are pipeline companies or their affiliates) mismeasured the volume and
heating content of natural gas produced from federal or Indian leases. As a
result, the relator alleges that the defendants underpaid, or caused others to
underpay, the royalties that were due to the United States for the production of
natural gas from those leases. In April 1999, the DOJ declined to intervene in
any of the cases.
The complaint seeks to recover all royalties, which the government should have
received if the heating content of natural gas produced from the leases in
question had been properly calculated, together with appropriate interest. The
complaint does not seek a specific dollar amount or quantify the royalties
claim. In addition, the complaint seeks treble damages that are provided by the
False Claims Act, civil penalties of not less than $5,000 and not more than
$10,000
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against each defendant for each violation of the False Claims Act, an order
requiring the defendants to discontinue certain measurement practices, and
reasonable expenses, attorney's fees, and costs incurred in connection with the
litigation.
On November 19, 1999, the Utility and PG&E GT-NW were part of a group of 255
coordinated defendants, which moved to dismiss the cases on a number of
procedural and substantive legal grounds before any discovery is taken. On May
18, 2001, after a hearing held in March 2001, the court denied the motion.
Shortly thereafter, many defendants asked the district court to certify a
question of law involved in the decision to the Tenth Circuit. That motion is
pending.
On July 20, 2000, the government moved to dismiss Grynberg's valuation claims
(essentially claims that defendants sell gas to affiliates at an artificially
low prices and use those prices for the royalty calculation). Briefing on the
government's motion is complete and oral argument was held on February 22, 2001.
A decision has not yet been issued. Even if the court grants the government's
motion, other claims would remain.
By its terms, the complaint alleges that mismeasurement (and hence underpayment
of royalties) occurred in every month for every federal or Indian lease for
approximately a 10-year period. Because of the relator's failure to plead with
particularity, the complaint does not allege facts that would allow one to
estimate the alleged damages. Nevertheless, the relator has filed a claim in the
Bankruptcy Court in the Utility's bankruptcy case for $2.48 billion, $2 billion
of which is based on Gyrnberg's calculation of penalties against the Utility,
which he alleges "may range up to $25,000 per violation per day since at least
1987."
Management believes the case is without merit and is vigorously defending it.
However, because the case has not progressed past its initial stages, it is not
possible to predict whether the outcome will have a material adverse impact on
PG&E Corporation's or the Utility's financial position or results of operations.
Baldwin Associates
On or about September 5, 2001, Baldwin Associates, Inc. (Baldwin) filed a claim
in the Bankruptcy Court in the Utility's bankruptcy case. The proof of claim
form seeks relief of $5 billion and indicates that the basis of the claim is
"taxes" and "other" ("economic and personal injury."). The form also indicates
that the debt was incurred "[b]eginning at least [sic] September 6, 2000." The
alleged claim does not provide any additional detail.
Analysis of Baldwin's alleged claim is at a preliminary stage, but the Utility
believes it to be without merit and intends to present rigorous objections to
the claim and to vigorously defend against it.
PG&E Corporation and the Utility are unable to predict whether the outcome of
this litigation will have a material adverse affect on their financial condition
or results of operation.
Wilson vs. PG&E Corporation and Pacific Gas and Electric Company
As previously disclosed in the Quarterly Reports on Form 10-Q filed by PG&E
Corporation and the Utility, two complaints were filed against PG&E Corporation
and the Utility in the Superior Court of the State of California, San Francisco
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County: Richard D. Wilson v. Pacific Gas and Electric Company, et al. (Wilson
I), and Richard D. Wilson v. Pacific Gas and Electric Company, et al. (Wilson
II). The Utility filed notice of automatic stay on April 11, 2001, pursuant to
the Bankruptcy Code. On April 19, 2001, the court signed orders based on
stipulation between PG&E Corporation and plaintiffs to stay all proceedings in
the cases as against PG&E Corporation. On September 7, 2001, plaintiffs
dismissed both actions without prejudice. A claim filed by Wayne Roberts in the
Utility's bankruptcy proceeding contains allegations that are similar but not
identical to the allegations contained in the Wilson cases. See discussion
below.
Wayne Roberts
On or about September 5, 2001, Wayne Roberts filed a purported "secured" claim
against the Utility in the Bankruptcy Court in the Utility's bankruptcy case.
The proof of claim form stated the total amount of claim as $40.00, although, in
the materials attached to the form, the claimant seeks payment to "PG&E
electricity ratepayers" of not less than $4 billion, plus interest, restitution,
attorneys' fees and costs. The claimant purports to bring the claim on behalf of
"himself, the public, and [a] class composed of PG&E electricity ratepayers," as
creditors. The allegations of the claim are similar but not identical to the
allegations in two actions earlier filed in the San Francisco Superior Court,
but then dismissed without prejudice, entitled Richard D. Wilson v. Pacific Gas
and Electric Company et al. The same lawyers who represent Wayne Roberts in his
alleged bankruptcy claim, represented plaintiff Richard D. Wilson in the earlier
Wilson cases.
Mr. Roberts asserts various legal theories including, but not limited to,
purported violations of California Business & Profession Code Section 17200,
California Public Utilities Code Sections 453, 817, 818, 841, and 851, 15 U.S.C.
Section 79i(a)(2), various "regulations," and the doctrines of "public trust"
and/or "public use," as well as constructive fraud, allegedly arising out of:
(a) formation of PG&E Corporation; (b) alleged dividend payments, and
repurchases of Utility common stock, made by the Utility; and (c) alleged tax
payments made by the Utility to PG&E Corporation through consolidated tax
preparation for the Utility and affiliate companies of PG&E Corporation.
Mr. Robert's claim contends that allegations, which relate to PG&E Corporation,
will be made in an adversary proceeding of the Bankruptcy Court, or in a state
court, provided the Bankruptcy Court permits Mr. Roberts to lift the automatic
stay.
Analysis of Mr. Roberts' claim is at a preliminary stage, but the Utility and
PG&E Corporation believe it to be without merit and intend to present rigorous
objections to the claim and to vigorously defend against it.
PG&E Corporation and the Utility are unable to predict whether the outcome of
this litigation will have a material adverse affect on their financial condition
or results of operation.
Item 3. Defaults Upon Senior Securities
The Utility has authorized 75 million shares of First Preferred Stock ($25 par
value) and 10 million shares of $100 First Preferred Stock ($100 par value),
which may be issued as redeemable or non-redeemable preferred stock. (The
Utility has not issued any $100 First Preferred Stock.) At September 30, 2001,
the Utility had issued and outstanding 5,784,825 shares of non-redeemable
preferred stock and 5,973,456 shares of redeemable preferred stock. The
Utility's redeemable preferred stock is subject to redemption at the Utility's
option, in whole or in part, if the Utility pays the specified redemption price
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plus accumulated and unpaid dividends through the redemption date. The Utility's
redeemable preferred stock with mandatory redemption provisions consists of 3
million shares of the 6.57 percent series and 2.5 million shares of the 6.30
percent series at December 31, 2000. The 6.57 percent series and 6.30 percent
series may be redeemed at the Utility's option beginning in 2002 and 2004,
respectively, at par value plus accumulated and unpaid dividends through the
redemption date. These series of preferred stock are subject to mandatory
redemption provisions entitling them to sinking funds providing for the
retirement of stock outstanding. At December 31, 2000, the redemption
requirements for the Utility's redeemable preferred stock with mandatory
redemption provisions are $4 million per year beginning 2002, and $3 million per
year beginning 2004, for the series 6.57 percent and 6.30 percent, respectively.
Holders of the Utility's non-redeemable preferred stock 5 percent, 5.5 percent,
and 6 percent series have rights to annual dividends per share ranging from
$1.25 to $1.50.
Due to the California energy crisis, the Utility's Board of Directors did not
declare the regular preferred stock dividends for the three-month periods ended
January 31, 2001 (normally payable on February 15, 2001), April 30, 2001
(normally payable May 15, 2001), and July 31, 2001 (normally payable August 15,
2001).
Dividends on all Utility preferred stock are cumulative. All shares of preferred
stock have voting rights and equal preference in dividend and liquidation
rights. Accumulated and unpaid dividends for the three-month periods ended
January 31, April 30, and July 31, 2001, amounted to $19 million. Upon
liquidation or dissolution of the Utility, holders of preferred stock would be
entitled to the par value of such shares plus all accumulated and unpaid
dividends, as specified for the class and series. Until cumulative dividends on
its preferred stock are paid, the Utility may not pay any dividends on its
common stock, nor may the Utility repurchase any of its common stock.
The Utility's total defaulted commercial paper outstanding as of September 30,
2001, was $873 million. As of June 30, 2001, the Utility had drawn and had
outstanding $938 million under the bank credit facility, which was also in
default. For the quarter ending September 30, 2001, the Utility did not make any
payments on its bank loan drawdowns or defaulted commercial paper.
With regard to certain pollution control bond-related debt of the Utility, the
Utility has been in default under the credit agreements with the banks that
provide letters of credit as credit and liquidity support for the underlying
pollution control bonds. These defaults included the Utility's non-payment of
other debt in excess of $100 million, the Utility's filing of a petition for
reorganization under Chapter 11 of the Bankruptcy Code and non-payment of
interest. As a result of these defaults, several of the letter of credit banks
caused the acceleration and redemption of four series of pollution control
bonds. All of these redemptions were funded by the letter of credit banks
resulting in loans from the banks to the Utility, which have not been paid. As
of September 30, 2001, the total principal of the bonds (and related loans)
accelerated and redeemed was $454 million. As of September 30, 2001, the Utility
did not make interest payments of $10.7 million on pollution control bonds
series 96C, 96E, 96F, and 97B. As of September 30, 2001, the Utility did not
make an interest payment of $2.7 million on pollution control bond series 96A
backed by bond insurance. With regard to certain pollution control bond-related
debt of the Utility backed by the Utility's mortgage bonds, an event of default
has occurred under the relevant loan agreements with the California Pollution
Control Financing Authority due to the Utility's bankruptcy filing.
The Utility's filing of a petition for reorganization under Chapter 11 of the
Bankruptcy Code also constitutes a default under the indenture that governs its
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medium-term notes ($287 million aggregate amount outstanding), five-year 7.375%
senior notes ($680 million aggregate amount outstanding), and floating-rate
notes ($1.24 billion aggregate amount outstanding). In addition, as of September
30, 2001, the Utility did not make interest payments on its medium-term notes,
its 7.375% senior notes, and its $1.24 billion floating rate notes. As of
September 30, 2001, the total arrearage of these interest payments was $79.1
million. Also as of September 30, 2001, the Utility did not make principal
payments on unsecured long-term debt of $2 million.
With regard to the 7.90% Quarterly Income Preferred Securities and the related
7.90% Deferrable Interest Debentures (debentures), the Utility's filing of a
petition for reorganization under Chapter 11 of the Bankruptcy Code is an event
of default under the applicable indenture. Pursuant to the related trust
agreement, the trustee is required to take steps to liquidate the trust and
distribute the debentures to the QUIPS holders.
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, 2001, was 1.98. Pacific Gas and Electric Company's
earnings to combined fixed charges and preferred stock dividends ratio for the
nine months ended September 30, 2001, was 1.91. The statement of the foregoing
ratios, together with the statements of the computation of the foregoing ratios
filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of
incorporating such information and exhibits into Registration Statement Nos.
33-62488, 33-64136, 33-50707, and 33-61959, relating to Pacific Gas and Electric
Company's various classes of debt and first preferred stock outstanding.
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits:
Exhibit 10.1 Pacific Gas and Electric Company Management Retention
Program (incorporated by reference from PG&E
Corporation and Pacific Gas and Electric Company's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 2001, Exhibit 10.1)
Exhibit 10.2 PG&E Corporation Management Retention Program
(incorporated by reference from PG&E Corporation and
Pacific Gas and Electric Company's Quarterly Report
on Form 10-Q for the quarter ended September 30,
2001, Exhibit 10.2)
Exhibit 11 Computation of Earnings Per Common Shares
(incorporated by reference from PG&E Corporation and
Pacific Gas and Electric Company's Quarterly Report
on Form 10-Q for the quarter ended September 30,
2001, Exhibit 11.)
Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges
for Pacific Gas and Electric Company (incorporated by
reference from PG&E Corporation and Pacific Gas and
Electric Company's Quarterly Report on Form 10-Q for
the
76
quarter ended September 30, 2001, Exhibit 12.1.)
Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas
and Electric Company (incorporated by reference from
PG&E Corporation and Pacific Gas and Electric
Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001, Exhibit 12.2)
(b) The following Current Reports on Form 8-K were filed during the third
quarter of 2001 and through the date hereof:
1. July 9, 2001 Item 5. Other Events
Item 7. Financial Statements, Pro Forma,
Financial Information, and
Exhibits
Exhibit 99 - Pacific Gas and
Electric Company
Income Statements for the
months ended April 30 and
May 31, 2001 and Balance
Sheets dated April 30 and
May 31, 2001,
respectively
2. July 30, 2001 Item 5. Other Events
3. September 7, 2001 Item 5. Other Events
Item 7. Financial Statements, Pro Forma,
Financial Information, and
Exhibits
Exhibit 99 - Pacific Gas and
Electric Company Income
Statement for the month ended
July 30, 2001, and Balance
Sheet dated July 30, 2001.
4. September 20, 2001 Item 5. Other Events
Item 7. Financial Statements, Pro Forma,
Financial Information, and
Exhibits
Exhibit 99 - Proposed form of
disclosure statement filed by
PG&E Corporation and Pacific
Gas and Electric Company,
together with Exhibit A
(Proposed plan of
reorganization under Chapter
11 of the Bankruptcy Code for
Pacific Gas and Electric
Company), Exhibit C
(Projected Financial
Information and Underlying
Assumptions), and Exhibit D
(Summary of Terms of
Long-Term Debt).
5. October 2, 2001 Item 5. Other Events
Item 7. Financial Statements, Pro Forma,
Financial Information, and
Exhibits
Exhibit 99 - Pacific Gas and
Electric Company Income
Statement for the month ended
August 31, 2001, and Balance
Sheet dated August 31, 2001.
6. October 25, 2001 Item 5. Other Events
Pacific Gas and Electric
Company's 1999 General Rate
Case Proceeding
7. November 1, 2001 Item 5. Other Events
77
A. Pacific Gas and Electric
Company's 2002 General Rate
Case Proceeding B. Pacific
Gas and Electric Company's
Retained Generation
Ratemaking Proceeding
78
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
By Christopher P. Johns
------------------------------
CHRISTOPHER P. JOHNS
Senior Vice President and Controller
(duly authorized officer and principal
accounting officer)
PACIFIC GAS AND ELECTRIC COMPANY
By Kent M. Harvey
------------------------------
KENT M. HARVEY
Senior Vice President, Chief Financial
Officer, and Treasurer (duly authorized
officer and principal financial officer)
Dated: March 5, 2002
79
Exhibit Index
Exhibit 10.1 Pacific Gas and Electric Company Management Retention
Program (incorporated by reference from PG&E
Corporation and Pacific Gas and Electric Company's
Quarterly Report on Form 10-Q for the quarter ended
September 30, 2001, Exhibit 10.1)
Exhibit 10.2 PG&E Corporation Management Retention Program
(incorporated by reference from PG&E Corporation and
Pacific Gas and Electric Company's Quarterly Report
on Form 10-Q for the quarter ended September 30,
2001, Exhibit 10.2)
Exhibit 11 Computation of Earnings Per Common Shares
(incorporated by reference from PG&E Corporation and
Pacific Gas and Electric Company's Quarterly Report
on Form 10-Q for the quarter ended September 30,
2001, Exhibit 11.)
Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges
for Pacific Gas and Electric Company (incorporated by
reference from PG&E Corporation and Pacific Gas and
Electric Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 2001, Exhibit 12.1.)
Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas
and Electric Company (incorporated by reference from
PG&E Corporation and Pacific Gas and Electric
Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2001, Exhibit 12.2)
80