FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C., 20549
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 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
Exact Name of other IRS
Commission Registrant Jurisdiction Employer
File as specified of Identification
Number in its charter Incorporation Number
- --------------- --------------- ------------- --------------
1-12609 PG&E Corporation California 94-3234914
1-2348 Pacific Gas and California 94-0742640
Electric Company
Pacific Gas and Electric Company PG&E Corporation
77 Beale Street One Market, Spear Tower
P.O. Box 770000 Suite 2400
San Francisco, California 94177 San Francisco, California 94105
- ------------------------------------------- ---------------------------------
(Address of principal executive offices) (Zip Code)
Pacific Gas and Electric Company PG&E Corporation
(415) 973-7000 (415) 267-7000
- ------------------------------------------- ---------------------------------
Registrant's telephone number, including area code
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding twelve months (or for such shorter period that the
registrant was required to file such reports), and (2) have been subject to such
filing requirements for the past 90 days.
Yes X No
----- -----
Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of latest practicable date.
Common Stock Outstanding, July 31, 2001:
PG&E Corporation 387,130,925 shares
Pacific Gas and Electric Company Wholly-owned by PG&E Corporation
1
PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
Form 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2001
TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION PAGE
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS 3
CONDENSED CONSOLIDATED BALANCE SHEETS 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS 6
PACIFIC GAS AND ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS 7
CONDENSED CONSOLIDATED BALANCE SHEETS 8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS 11
NOTE 1: GENERAL 13
NOTE 2: THE CALIFORNIA ENERGY CRISIS 16
NOTE 3: VOLUNTARY PETITION FOR RELIEF UNDER CHAPTER 11 28
NOTE 4: PRICE RISK MANAGEMENT 31
NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE
PREFERRED SECURITIES OF TRUST HOLDING SOLELY
UTILITY SUBORDINATED DEBENTURES 33
NOTE 6: COMMIMENTS & CONTINGENCIES 34
NOTE 7: SEGMENT INFORMATION 40
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS 43
LIQUIDITY AND FINANCIAL RESOURCES 45
STATEMENT OF CASH FLOWS 50
RESULTS OF OPERATIONS 53
REGULATORY MATTERS 61
ENVIRONMENTAL MATTERS 64
PRICE RISK MANAGEMENT ACTIVITIES 67
LEGAL MATTERS 71
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 72
PART II. OTHER INFORMATION 73
ITEM 1. LEGAL PROCEEDINGS 73
ITEM 3. DEFAULTS UPON SENIOR SECURITIES 75
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 77
ITEM 5. OTHER INFORMATION 81
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K 81
SIGNATURE 83
2
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 Six months ended
June 30, June 30,
----------------- ----------------
2001 2000 2001 2000
------- ------- ------ ------
Operating Revenues
Utility $ 2,309 $ 2,296 $ 4,871 $ 4,514
Energy commodities and services 2,704 3,342 6,817 6,132
------ ------ ------ ------
Total operating revenues 5,013 5,638 11,688 10,646
Operating Expenses
Cost of energy for utility 67 1,157 3,300 1,953
Cost of energy commodities and services 2,335 3,047 6,174 5,519
Operating and maintenance 897 743 1,585 1,460
Depreciation, amortization, and decommissioning 259 69 514 416
Reorganization professional fees and expenses 8 - 8 -
------ ------ ------ ------
Total operating expenses 3,566 5,016 11,581 9,348
------ ------ ------ ------
Operating income 1,447 622 107 1,298
Reorganization interest income 32 - 32 -
Interest income 42 26 77 50
Interest expense (312) (182) (559) (365)
Other income (expense), net 4 (14) (5) (23)
Income Before Income Taxes 1,213 452 (348) 960
Income tax provision (benefit) 463 204 (147) 432
------ ------ ------ ------
Net Income (Loss) $ 750 $ 248 $ (201) $ 528
====== ====== ====== ======
Weighted average common shares outstanding 363 361 363 361
------ ------ ------ ------
Earnings (Loss) Per Common Share, Basic
Net Earnings (Loss) $2.07 $ .69 $(0.55) $ 1.46
====== ====== ====== ======
Earnings (Loss) Per Common Share, Diluted
Net Earnings (Loss) $2.07 $ .68 $(0.55) $ 1.45
====== ====== ====== ======
Dividends Declared Per Common Share $ - $ .30 $ - $ .60
====== ====== ====== ======
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
3
PG&E CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
Balance at
--------------------------
June 30, December 31,
2001 2000
----------- ------------
ASSETS
Current Assets
Cash and cash equivalents $ 683 $ 899
Short-term investments 3,757 1,634
Accounts receivable:
Customers (net of allowance for doubtful accounts of
$103 million and $71 million, respectively) 2,894 4,342
Regulatory balancing accounts 46 222
Price risk management 2,656 2,039
Inventories 501 392
Income taxes receivable - 1,241
Prepaid expenses and other 447 406
------- -------
Total current assets 10,984 11,175
Property, Plant, and Equipment
Utility 24,341 23,872
Non-utility:
Electric generation 2,671 2,008
Gas transmission 1,559 1,542
Construction work in progress 617 900
Other 123 147
------- -------
Total property, plant, and equipment (at original cost) 29,311 28,469
Accumulated depreciation and decommissioning (12,350) (11,878)
------- -------
Net property, plant, and equipment 16,961 16,591
Other Noncurrent Assets
Regulatory assets 1,872 1,773
Nuclear decommissioning funds 1,332 1,328
Price risk management 1,045 2,026
Other 3,202 2,398
------- -------
Total noncurrent assets 7,451 7,525
------- -------
TOTAL ASSETS $ 35,396 $ 35,291
======= =======
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, except share amounts)
Balance at
--------------------------
June 30, December 31,
2001 2000
----------- ------------
LIABILITIES AND EQUITY
Liabilities Not Subject to Compromise
Current Liabilities
Short-term borrowings $ 445 $ 4,530
Long-term debt, classified as current 10 2,391
Current portion of rate reduction bonds 290 290
Accounts payable:
Trade creditors 1,198 5,856
Regulatory balancing accounts 352 196
Other 535 459
Price risk management 2,548 1,999
Other 813 1,563
------- -------
Total current liabilities 6,191 17,284
Noncurrent Liabilities
Long-term debt 6,398 4,736
Rate reduction bonds 1,600 1,740
Deferred income taxes 1,795 1,656
Deferred tax credits 173 192
Price risk management 1,029 1,867
Other 3,903 3,864
------- -------
Total noncurrent liabilities 14,898 14,055
Liabilities Subject to Compromise
Financing debt 5,792 -
Trade creditors 5,168 -
------- -------
Total liabilities subject to compromise 10,960 -
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 share,
issued 387,177,497 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 (2,305) (2,105)
Accumulated other comprehensive loss (109) (4)
------- -------
Total common stockholders' equity 2,867 3,172
Commitments and Contingencies (Notes 1, 2, 3, and 6) - -
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 35,396 $ 35,291
======= =======
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
5
PG&E CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Six months ended June 30,
-------------------------
2001 2000
----------- ----------
Cash Flows From Operating Activities
Net income (loss) $ (201) $ 528
Adjustments to reconcile net income (loss) to
Net cash provided (used) by operating activities:
Depreciation, amortization, and decommissioning 514 416
Deferred income taxes and tax credits-net 120 111
Price risk management assets and liabilities, net (30) (20)
Other deferred charges and noncurrent liabilities (174) (369)
Net effect of changes in operating assets and liabilities:
Short-term investments (2,123) 139
Accounts receivable-trade 1,448 (505)
Inventories (109) 158
Accounts payable 586 594
Accrued taxes 1,241 127
Regulatory balancing accounts payable 332 190
Other working capital (791) 314
Other-net (116) (8)
------- -------
Net cash provided by operating activities 697 1,675
------- -------
Cash Flows From Investing Activities
Capital expenditures (818) (670)
Other-net (247) (10)
------- -------
Net cash used by investing activities (1,065) (680)
------- -------
Cash Flows From Financing Activities
Net repayments under credit facilities (1,033) (482)
Long-term debt issued 2,138 54
Long-term debt matured, redeemed, or repurchased (844) (346)
Common stock issued - 22
Dividends paid (109) (217)
------- -------
Net cash provided (used) by financing activities 152 (969)
------- -------
Net Change in Cash and Cash Equivalents (216) 26
Cash and Cash Equivalents at January 1 899 281
------- -------
Cash and Cash Equivalents at June 30 $ 683 $ 307
======= =======
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 268 $ 344
Income taxes paid (refunded) - net (1,241) 23
Transfer of liabilities and other payables subject to
compromise from operating payables and liabilities 10,960 -
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
6
PACIFIC GAS AND ELECTRIC COMPANY, A DEBTOR-IN-POSSESSION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
Three months Six months
ended June 30, ended June 30
---------------- -----------------
2001 2000 2001 2000
------ ------ ------ ------
Operating Revenues
Electric $ 1,497 $ 1,801 $ 2,756 $ 3,402
Gas 812 495 2,115 1,112
------ ------ ------ ------
Total operating revenues 2,309 2,296 4,871 4,514
Operating Expenses
Cost of electric energy (362) 975 1,955 1,488
Cost of gas 429 182 1,345 465
Operating and maintenance 676 543 1,208 1,094
Depreciation, amortization, and decommissioning 222 44 439 345
Reorganization professional fees and expenses 8 - 8 -
------ ------ ------ ------
Total operating expenses 973 1,744 4,955 3,392
------ ------ ------ ------
Operating Income (Loss) 1,336 552 (84) 1,122
Reorganization interest income 32 - 32 -
Interest income 17 12 24 18
Interest expense (contractual interest of $195 million
and $396 million for the three- and six-months ended
June 30, 2001, respectively) (257) (144) (458) (285)
Other income (expense), net (2) - (6) (1)
------ ------ ------ ------
Income (Loss) Before Income Taxes 1,126 420 (492) 854
Income tax provision (benefit) 424 198 (200) 398
------ ------ ------ ------
Net Income (Loss) 702 222 (292) 456
Preferred dividend requirement 6 6 12 12
------ ------ ------ ------
Income (Loss) Available for (Allocated to) Common Stock $ 696 $ 216 $ (304) $ 444
====== ====== ====== ======
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 BALANCE SHEETS
(in millions, except share amounts)
Balance at
-------------------------
June 30, December 31,
2001 2000
---------- -----------
ASSETS
Current Assets
Cash and cash equivalents $ 132 $ 111
Short-term investments 3,125 1,283
Accounts receivable:
Customer (net of allowance for doubtful accounts of
$54 million and $52 million, respectively) 1,547 1,711
Related parties 20 6
Regulatory balancing account 46 222
Inventories:
Gas stored underground and fuel oil 262 146
Materials and supplies 126 134
Income taxes receivable - 1,120
Prepaid expenses and other 210 45
------ ------
Total current assets 5,468 4,778
Property, Plant, and Equipment
Electric 16,787 16,335
Gas 7,554 7,537
Construction work in progress 266 249
------ ------
Total property, plant, and equipment (at original cost) 24,607 24,121
Accumulated depreciation and decommissioning (11,521) (11,120)
------ ------
Net property, plant, and equipment 13,086 13,001
Other Noncurrent Assets
Regulatory assets 1,843 1,716
Nuclear decommissioning funds 1,332 1,328
Other 1,487 1,165
------ ------
Total noncurrent assets 4,662 4,209
------ ------
TOTAL ASSETS $ 23,216 $ 21,988
====== ======
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, except share amounts)
Balance at
---------------------------
June 30, December 31,
2001 2000
----------- ------------
LIABILITIES AND 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 345 3,688
Related parties 7 138
Regulatory balancing accounts 352 196
Other 300 363
Deferred income taxes 45 172
Other 297 670
-------- --------
Total current liabilities 1,636 10,970
Noncurrent Liabilities
Long-term debt 3,370 3,342
Rate reduction bonds 1,600 1,740
Deferred income taxes 1,087 929
Deferred tax credits 173 192
Other 3,001 2,968
-------- --------
Total noncurrent liabilities 9,231 9,171
Liabilities Subject to Compromise
Financing debt 5,792 -
Trade creditors 5,356 -
-------- --------
Total liabilities subject to compromise 11,148 -
Preferred Stock With Mandatory Redemption Provisions
6.30% and 6.57%, outstanding 5,500,000 shares,
due 2002-2009 137 137
Company Obligated Mandatorily Redeemable Preferred Securities
of Trust Holding Solely Utility Subordinated Debentures
7.90%, 12,000,000 shares due 2025 - 300
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 1,606 1,606
800,000,000 shares, issued 321,314,760 shares
Common stock held by subsidiary, at cost, 19,481,213 shares (475) (475)
Additional paid-in capital 1,964 1,964
Accumulated deficit (2,283) (1,979)
Accumulated other comprehensive loss (42) -
-------- --------
Total stockholders' equity 1,064 1,410
Commitments and Contingencies (Notes 1, 2, 3, and 6) - -
-------- --------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 23,216 $ 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 STATEMENTS OF CASH FLOWS
(in millions)
Six months ended
June 30,
------------------
2001 2000
------- -------
Cash Flows From Operating Activities
Net income (loss) $ (292) $ 456
Adjustments to reconcile net income to
Net cash provided (used) by operating activities:
Depreciation, amortization, and decommissioning 439 345
Deferred income taxes and tax credit-net 12 170
Price risk management assets and liabilities, net (38) -
Other deferred charges and noncurrent liabilities (272) (303)
Net effect of changes in operating assets and liabilities:
Short-term investments (1,842) (6)
Accounts receivable 619 (46)
Income tax receivable 1,120 -
Inventories (108) 15
Accounts payable 606 399
Accrued taxes - 99
Regulatory balancing accounts, net 332 190
Other working capital (99) (16)
Other-net 366 (5)
------- -------
Net cash provided by operating activities 843 1,298
------- -------
Cash Flows From Investing Activities
Capital expenditures (575) (572)
Other-net 34 (16)
------- -------
Net cash used by investing activities (541) (588)
------- -------
Cash Flows From Financing Activities
Net borrowings (repayments) under credit facilities (28) 31
Long-term debt matured, redeemed, or repurchased (252) (216)
Common stock repurchased - (275)
Dividends paid - (250)
Other-net (1) 4
------- -------
Net cash used by financing activities (281) (706)
------- -------
Net Change in Cash and Cash Equivalents 21 4
Cash and Cash Equivalents at January 1 111 80
------- -------
Cash and Cash Equivalents at June 30 $ 132 $ 84
======= =======
Supplemental disclosures of cash flow information
Cash paid for:
Interest (net of amounts capitalized) $ 265 $ 261
Income taxes paid (refunded) - net (1,120) -
Transfer of liabilities and other payables subject to
compromise from operating payables and liabilities 11,148 -
The accompanying Notes to the Condensed Consolidated Financial Statements are an
integral part of this statement.
10
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) on January 1, 1997. The Utility, incorporated in California in 1905,
is the predecessor of PG&E Corporation. Effective with PG&E Corporation's
formation, the Utility's interests in its unregulated subsidiaries were
transferred to 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.
This Quarterly Report on Form 10-Q is a combined report of PG&E Corporation and
the Utility. Therefore, the Notes to the Condensed Consolidated Financial
Statements apply to both PG&E Corporation and the Utility. PG&E Corporation's
condensed consolidated financial statements include the accounts of PG&E
Corporation, the Utility, and PG&E Corporation's wholly owned and controlled
subsidiaries. The Utility's 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 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. All
significant intercompany transactions have been eliminated from the condensed
consolidated financial statements.
Certain amounts in the prior year's condensed consolidated financial statements
have been reclassified to conform to the 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, and PG&E Corporation's and the Utility's other reports
filed with the Securities and Exchange Commission since their 2000 Form 10-K 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.
Accounting for Price Risk Management Activities
11
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 a decrease
of $243 million to accumulated other comprehensive income. The Utility's
transition adjustment to implement this new Statement resulted in a non-material
decrease to earnings and an increase of $90 million to accumulated other
comprehensive income.
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 until the hedged item is recognized in
earnings. Net gains or losses recognized for the three- and six-month periods
ended June 30, 2001, were included in various places on the income statement
including energy commodities service revenue, cost of energy commodities and
services, other income (expense), net, or interest income or interest expense.
Contracts for the physical delivery of purchase and sale quantities under the
normal course of business are exempt from the requirements of SFAS No. 133 under
the normal purchases and sales exception, and thus are not reflected on the
balance sheet at fair value. The Financial Accounting Standards Board(FASB) is
considering an interpretation by the Derivatives Implementation Group (DIG) that
indicates that certain forward contracts with embedded optionality cannot
qualify for the normal purchases and sales exception. Any gains or losses from
the changes in fair value of these contracts in PG&E Corporation's non-regulated
businesses will impact the income statement unless those contracts qualify for
hedge accounting treatment. PG&E Corporation is currently reviewing its
contracts to evaluate the impact of these interpretations on its financial
statements, and will implement this guidance, as applicable, on a prospective
basis.
As of June 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 and for interest rate risk it is
through March 2014.
The Utility had Power Exchange (PX) block-forward contracts valued at $243
million, which were derecognized in February 2001 when they were seized by
California Governor Gray Davis for the benefit of the State, acting under
California's Emergency Services Act (the Act). The block-forward contracts had
an unrealized gain at the time they were seized. Under the Act, the State must
pay the Utility for the reasonable value of the contracts, although the PX may
seek to recover the monies that the Utility owes to the PX from any proceeds
realized from the contracts. The Utility has filed a complaint against the
State to recover the value of the seized contracts.
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 gas contracts terminated during the first six months of the year was $60
million, net of taxes and regulatory impact. This balance is being amortized
out of accumulated other comprehensive income at the same rate that hedged items
are recognized in earnings.
12
Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing net income (loss) 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 (loss) and
weighted average common shares outstanding for calculating basic and diluted net
income (loss) per share.
Three months Six months
ended June 30, ended June 30,
-------------------- ---------------------
2001 2000 2001 2000
(in millions) ------ ------ ------- ------
Net Income (Loss) $ 750 $ 248 $ (201) $ 528
----- ----- ------ -----
Weighted average common shares outstanding 363 361 363 361
Add: Outstanding options reduced by the number of shares
that could be repurchased with the proceeds from such
purchase - 1 - 1
----- ----- ----- -----
Shares outstanding for diluted calculation 363 362 363 362
----- ----- ----- -----
Earnings (Loss) per common share, basic $2.07 $ .69 $(0.55) $1.46
Earnings (Loss) per common share, dilutive $2.07 $ .68 $(0.55) $1.45
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 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
Standard, 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 Pacific Gas and Electric
Company do not expect that implementation of this Standard will have a
significant impact on its financial statements.
Also, in June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." This Standard eliminates the amortization of goodwill, and requires
that goodwill be reviewed annually for impairment. This Standard also requires
that the useful lives of previously recognized intangible assets be reassessed
and the remaining amortization periods be adjusted accordingly. This Standard
is effective for fiscal years beginning after December 15, 2001, and affects all
13
goodwill and other intangible assets recognized on the company's statement of
financial position at that date, regardless of when the assets were initially
recognized. PG&E Corporation and Pacific Gas and Electric Company have not yet
determined the effects of this Standard on its financial statements.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This Standard is effective for fiscal years beginning after June
15, 2002, and provides accounting requirements for asset retirement obligations
associated with tangible long-lived assets. PG&E Corporation and Pacific Gas
and Electric Company have not yet determined the effects of this Standard on its
financial statements.
NOTE 2: THE CALIFORNIA ENERGY CRISIS
In 1998, California became one of the first states in the country to implement
electric industry restructuring and establish a competitive market framework for
electric generation. Electric industry restructuring was mandated by the
California Legislature in Assembly Bill 1890 (AB 1890). The electric industry
restructuring 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 a competitive 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 competitive
market framework called for the creation of the PX and the Independent System
Operator (ISO). Before it ceased operating, 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 for generation to, and purchase all electricity for its 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.
Beginning in June 2000, wholesale prices for electricity sold through the PX and
ISO experienced unanticipated and massive increases. The average price of
electricity purchased by the Utility for the benefit of its customers was 18.2
cents per kilowatt-hour (kWh) for the period of June 1 through December 31,
2000, compared to 4.2 cents per kWh during the same period in 1999. The Utility
was only permitted to collect approximately 5.4 cents per kWh in 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. In order to finance the higher costs of energy, during the third and
fourth quarter of 2000, the Utility increased its lines of credit to $1,850
million (net increase of $850 million), issued $1,240 million of debt under a
364-day facility, and issued $680 million of five-year notes.
The Utility continued to finance the higher costs of wholesale power while
interested parties evaluated various solutions to the energy crisis. In
November 2000, the Utility filed its Rate Stabilization Plan (RSP), which sought
to end the rate freeze and pass along the increased wholesale electric costs to
customers through increased rates. The CPUC evaluated the Utility's proposal
and deferred its decision until March 2001, although the CPUC did increase rates
one cent per kWh for 90 days effective January 4, 2001. This increase resulted
in approximately $70 million of additional revenue per month, which was not
nearly enough to cover the higher wholesale costs of electricity, nor did it
14
help with the costs already incurred.
By January 16, 2001, the Utility had borrowed more than $3.0 billion under its
various credit facilities to pay its energy costs. As a result of the
California energy crisis 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. Commencing 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 and generators were
only selling to the Utility under emergency action taken by the U.S. Secretary
of Energy.
In January 2001, the California Legislature and the Governor authorized the
California Department of Water Resources (DWR) to purchase wholesale electric
energy on behalf of the Utility's retail customers.
On March 27, 2001, the CPUC authorized an average increase in retail rates of
3.0 cents per kWh, which was in addition to the emergency 1.0 cent per kWh
surcharge adopted on January 4, 2001 by the CPUC. 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 3.0 cent per Kwh surcharge until June 1, 2001, when the
rate design was adopted by the CPUC. As a result of the delay in
implementation, the additional surcharge that went into effect on June 1, 2001
was 3.5 cents per kWh, of which 0.5 cents per kWh amortizes the under-collection
that accrued between March 27 and the June 1, 2001 implementation date over the
twelve month period ending June 2002.
In light of the magnitude of the under-collected purchased power costs and the
lack of solutions to the energy crisis, on April 6, 2001, the Utility sought
protection from its creditors through a Chapter 11 bankruptcy filing. The
filing for bankruptcy and the related uncertainty around the terms and
conditions of any reorganization plan that is ultimately adopted will have a
significant impact on the Utility's future liquidity and results of operations.
PG&E Corporation, itself, had cash and short-term investments of $272 million at
June 30, 2001, and believes that the funds will be adequate to maintain its
operations through and beyond 2001. In addition, PG&E Corporation believes that
itself and its other subsidiaries not subject to CPUC regulation are
substantially protected from the continuing liquidity and financial difficulties
of the Utility. A discussion of the events leading up to the bankruptcy filing,
PG&E Corporation's and the Utility's actions, and the ongoing uncertainty
follows.
Transition Period and Rate Freeze
California's deregulation legislation passed by the California Legislature in
1996 established a transition period, which was to begin in 1998. During this
period, electric rates for all customers were frozen at 1996 levels, with rates
for residential and small commercial customers being reduced in 1998 by 10% and
frozen at that level. During the transition period, investor-owned utilities
were given the opportunity to recover their transition costs. Transition costs
were generation-related costs that were expected to be uneconomic under the new
industry structure.
15
To pay for the 10% rate reduction, the Utility refinanced $2.9 billion (the
expected revenue reduction from the rate decrease) of its transition costs with
the proceeds from the sale of rate reduction bonds. The bonds allow for the
rate reduction by lowering the carrying cost on a portion of the transition
costs and by deferring recovery of a portion of the transition costs until after
the transition period. During the rate freeze, the rate reduction bond debt
service did not increase the Utility customers' electric rates. If the
transition period ends before March 31, 2002, the Utility may be obligated to
return a portion of the economic benefits of the transaction to customers. The
timing of any such return and the exact amount of such portion, if any, have not
yet been determined.
The rate freeze was scheduled to end on the earlier of March 31, 2002, or the
date the Utility had recovered all of its transition costs. The Utility
believes it recovered its eligible transition costs possibly as early as the end
of May 2000. At August 31, 2000, the Utility's remaining transition costs were
less than a then-recently negotiated $2.8 billion hydroelectric generation asset
valuation. If the final valuation for the hydroelectric assets is greater than
$2.8 billion, as the Utility expects, the Utility will have recovered its
transition costs earlier. The under-collected wholesale electricity costs as of
the end of the earlier determined transition period will be less than the August
31, 2000 balance of $2.2 billion, and could be zero depending on the ultimate
valuation of the hydroelectric generating facilities and when the transition
period actually ends. 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.
Wholesale Prices of Electricity
As previously stated, beginning in June 2000, the Utility experienced
unanticipated and massive increases in the wholesale costs of the electricity
purchased from the PX and ISO on behalf of its retail customers. 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 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, 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.
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 counterparty, and noted
the existence of unresolved issues regarding how to ensure these
creditworthiness requirements for real-time transactions and emergency dispatch
16
orders issued by the ISO to power sellers. The Utility believes that its only
responsibility for third party power delivered to its customers is to pay the
DWR the amount collected from customers, whether the third party power is
purchased by a creditworthy buyer or whether the purchase is facilitated by a
creditworthy counterparty.
The generation-related cost component of frozen retail rates, which provides for
recovery of generation costs, including wholesale electricity purchased by the
Utility and, if available, for recovery of transition costs, was 5.4 cents per
kWh, during the six months ended June 30, 2000. In 2001, the CPUC approved two
rate increases, which increased the generation-related cost component. On
January 4, 2001, the generation-related cost component increased 1.0 cent per
kWh. On June 1, 2001, the generation-related cost component increased by 3.5
cents per kWh. As discussed below, the CPUC approved an average 3.0 cents per
kWh surcharge for power costs incurred after March 27, 2001, but the Utility did
not begin collecting in rates the 3.0 cents per kWh surcharge until June 1,
2001. At the time of implementation, the actual surcharge was 3.5 cents per kWh
to reflect the under-collection that accrued due to the delay in implementation.
Through April 6, 2001, the excess of wholesale electricity costs billed to the
Utility by the ISO above the generation-related cost component available in
frozen rates has been expensed as incurred and is included in the cost of
electric energy on the Utility's Condensed Consolidated Statement of Operations.
The amount of under-collected purchased power costs incurred for the six-month
period ended June 30, 2001 was approximately $.9 billion. The under-collected
purchased power costs accrued as of March 31, 2001, included an estimated cost
of $579 million for the month of March based upon usage and historical market
price estimates. In May 2001, the ISO provided the invoice for its March
purchases, which totaled $257 million. An adjustment for the difference between
the estimated amount at March 31, 2001, and the actual amount was recorded in
the second quarter as a reduction to the Cost of Electric Energy in the
Consolidated Statement of Operations.
Under current CPUC decisions, if the under-collected purchased power costs are
not recovered through frozen rates by the end of the transition period, they
cannot be recovered. However, in the CPUC decision adopting the 3.0 cent per
kWh rate increase, the CPUC indicated that in light of recent legislative action
and regulatory developments, it would be premature and unwise to opine as to
the ultimate disposition of this under-collection. Once the transition period
has ended and the rate freeze is over, the Utility's customers will be
responsible for wholesale electricity costs. However, actual changes in
customer rates will not occur until new retail rates are authorized by the CPUC
or, to the extent allowed, by the Bankruptcy Court.
The under-collected purchased power costs would generally 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 has determined that it can no longer conclude that its uncollected
wholesale electricity costs and remaining transition costs are probable of
recovery in future rates. Therefore, such costs are expensed as incurred.
Mitigation Efforts
The Utility is actively exploring ways to reduce its exposure to wholesale
electricity price volatility and to recover its written-off under-collected
wholesale electricity costs and Transition Cost Balancing Account (TCBA)
balances. As previously indicated, the Utility believes the transition period
has ended and filed an application with the CPUC asking it to so rule. The
Utility has also filed an application with the FERC to address the current
market crisis, filed a lawsuit against the CPUC in federal district court,
17
worked with interested parties to address power market dysfunction before
appropriate regulatory bodies, hedged a portion of its open procurement position
against higher purchased power costs through forward purchases, and filed an
application with the CPUC seeking approval of a five-year rate stabilization
plan. The Utility's actions and related activities are discussed below.
Application with the FERC
- -------------------------
On October 16, 2000, the Utility joined with Southern California Edison (SCE)
and The Utility Reform Network (TURN) in filing a petition with the FERC
requesting that the FERC; (1) immediately find the California wholesale
electricity market to be not workably competitive and the resulting prices to be
unjust and unreasonable; (2) immediately impose a cap on the price for energy
and ancillary services; and (3) institute further expedited proceedings
regarding the market failure, mitigation of market power, structural solutions,
and responsibility for refunds.
On December 15, 2000, the FERC issued an order in response to the above filing.
The remedies proposed by the FERC included, among other things; (1) eliminating
the requirement that the California investor-owned utilities must sell all of
their power into, and buy all of their power needs from, the PX; (2) modifying
the single price auction so that bids above $150 per megawatt hour (MWh) (15.0
cents per kWh) cannot set the market clearing prices paid to all bidders,
effective January 1, 2001 through April 30, 2001; (3) establishing an
independent governing board for the ISO; and (4) establishing penalties for
under-scheduling power loads. The FERC did not order any refunds based on its
findings, but announced its intent to retain the discretion to order refunds for
wholesale electricity costs incurred from October 2000 through December 31,
2002. In March 2001, the FERC ordered refunds of $69 million for January 2001
and indicated it would continue to review December 2000 wholesale prices. In
April 2001, the FERC ordered refunds of $588 thousand for February and March
2001. The generators have appealed the decisions. Any refunds will be offset
against amounts owed the generators.
During June and July 2001, a FERC administrative law judge conducted settlement
negotiations between power sellers, representatives of the State of California,
California investor-owned utilities and other interested parties, to try to
reach an agreement about calculation of potential refunds. The settlement
negotiations were unsuccessful and on July 25, 2001, the FERC issued an order
that limits potential refunds to the ISO and PX spot markets during the period
of October 2, 2000 through June 20, 2001, and adopted a refund calculation
methodology that uses daily spot gas prices and includes a 10% premium on prices
after January 5, 2001, to reflect the added risk to the sellers resulting from
the lack of creditworthiness of the California investor owned utilities. The
ISO has 15 days to submit a re-creation of the mitigated prices that result from
using the methodology to the administrative law judge (ALJ) overseeing the
proceedings. The FERC directed the ALJ to make findings of fact with respect
to: (1) the mitigated price in each hour of the refund period; (2) the amount
of refunds owed by each supplier according to the methodology established; and
(3) the amount currently owed to each supplier (with separate quantities due
from each entity) by the ISO, the investor owned utilities, and the State of
California. The ALJ is to then certify his findings of fact to the FERC within
45 days after the receipt of the material from the ISO. A prehearing conference
is scheduled to be held on August 13, 2001 to address procedural issues related
to the evidentiary hearings developing a record on the scope and methodology for
calculating refunds announced in the July 25, 2001 order.
18
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. Although ruling in the Utility's favor on
five of the six grounds for dismissal, the court found that the Utility's
complaint was not ripe because some of the CPUC's decisions that the Utility was
challenging were interim orders that will only become final upon a grant or
denial of rehearing. The Utility filed a request for rehearing of the CPUC's
decisions. Under applicable rules, if the CPUC has not acted on the request
within 60 days of filing, the request is deemed denied. While the CPUC has not
yet acted on the Utility's request, the 60-day period has expired and the
Utility believes the decisions have become final. Therefore, the Utility
intends to refile its case in federal district court shortly.
Legislative Action
- ------------------
On February 1, 2001, the governor of California signed into law AB 1X. AB 1X
extended a preliminary authority of the DWR to purchase power. Public Utilities
Code Section 360.5, adopted in AB 1X, requires the CPUC to determine the portion
of each electric utility's existing electric retail rate that represents the
difference between the generation related component of the utility's retail rate
in effect on January 5, 2001, and the sum of the costs of the utility's own
generation, qualifying facilities (QFs) contracts, existing bilateral contracts,
and ancillary services (the California Procurement Adjustment or CPA).
Currently, the CPA is just a calculation and is not paid to the DWR. Initially,
the DWR indicated that it intended to buy power only at "reasonable prices" to
meet the utilities' net open position, leaving the ISO to buy the remainder. AB
1X does not address whether or how the Utility will be able to pay for the ISO's
wholesale power costs billed to the Utility that exceed the generation-related
costs components of electric rates. 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. As discussed above, the Utility has expensed these costs
from January through April 6, 2001 in the accompanying financial statements.
Although the Utility continues to receive bills from ISO for its power purchases
made after April 6, 2001, the Utility has recorded only the ISO's grid
management charge as an expense after April 6, 2001. It is not clear whether and
to what extent the Utility will ultimately be responsible for the ISO costs
billed to the Utility.
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.
Further, it is unclear how much of the ISO's power purchases have been made by
the DWR on behalf of the Utility's customers. On June 21, 2001, the Utility
received a request from the DWR that the Utility pay the DWR the amounts
required by current CPUC orders for the DWR's out-of-market purchases made on
19
behalf of the Utility's customers between January 17, 2001 and June 2, 2001,
pursuant to AB 1X. The Utility has previously received invoices from the ISO
for what the Utility believes may be the same energy.
The amounts requested by the DWR in its June 21, 2001 invoices are based on the
amounts that the Utility is authorized to collect from customers pursuant to AB
1X and current CPUC orders, which are significantly less than the ISO invoices,
which are based on market prices. However, the CPUC orders establishing the
amount the Utility is required to collect and pay the DWR are interim and
subject to revision when the CPUC allocates the DWR's overall revenue
requirements under AB 1X. Since the Utility believes that it is merely a pass
through entity for such costs and related revenues, the Utility does not reflect
these amounts in its Consolidated Statements of Operations.
A determination that the DWR is the creditworthy buyer or counterparty for the
ISO's third-party purchases in accordance with the FERC tariffs could result in
a reversal of the prior recorded ISO expenses and could result in a material
increase to earnings depending on the amount ultimately authorized by the CPUC
to be collected by the Utility from ratepayers on the DWR's behalf.
Rate Stabilization Plan
- -----------------------
On November 22, 2000, the Utility filed an application with the CPUC seeking
approval of a five-year RSP beginning on January 1, 2001. The Utility requested
an initial average rate increase of 22.4%. The Utility also proposed that it
receive actual costs, including a regulated return, for electricity generation
provided by it with the idea that profits that would have been generated at
market rates be recovered from customers later in the five-year rate
stabilization period. With respect to Diablo Canyon Nuclear Power Plant (Diablo
Canyon) the Utility has proposed to defer all profits (discussed below in
"Diablo Canyon Benefits Sharing"), until 2003, when the allocation of revenues
between ratepayers and shareholders will be readjusted. The readjustment is
intended to allow, by the end of 2005, the total net revenues earned by Diablo
Canyon, over the five-year plan, to be allocated equally between shareholders
and ratepayers according to existing CPUC decisions.
On January 4, 2001, the CPUC issued an emergency interim decision denying the
Utility's request for a rate increase. Instead, the decision permitted the
Utility to establish an interim surcharge applied to electric rates on an equal-
cents-per-kWh basis of 1.0 cent per kWh, subject to refund and adjustment. The
surcharge was to remain in effect for 90 days from the effective date of the
decision. The Utility was required to establish a balancing account to track
the revenue provided by the surcharge and to apply these revenues to ongoing
wholesale electricity costs. The surcharge was made permanent in the CPUC's
March 27, 2001 decision, referred to below.
On January 26, 2001, an assigned CPUC commissioner's ruling was issued in the
Utility's RSP proceeding. The ruling stated that in phase one of the case, the
scope of the proceeding would include (1) reviewing the independent audit of the
Utility's accounts to determine whether there is a financial necessity for
additional relief for the utilities, (2) reviewing TURN's accounting proposal to
transfer the under-collected balances in the utilities Transition Revenue
Accounts (TRAs) to their respective TCBAs and reviewing the generation
memorandum accounts, and (3) considering whether the rate freeze has ended only
on a prospective basis.
On January 30, 2001, the independent consultants engaged by the CPUC issued
their review report on the Utility's financial position as of December 3, 2000,
as well as that of PG&E Corporation and the Utility's affiliates. The review
20
found that the Utility made an accurate representation of its financial
situation noting accurate representations of its borrowing capabilities, credit
condition, and events of default. The review also found that the Utility
accurately represented recorded entries to its TRA and TCBA. The review alleged
certain deficiencies with respect to bidding strategies, cash conservation
matters, and cash flow forecast assumptions. The Utility filed rebuttal
testimony on February 14, 2001. Hearings to consider the issues and reports of
the independent consultants began on February 20, 2001.
On March 27, 2001, the CPUC ruled on parts of the Utility's RSP and granted an
increase in rates by adopting an average 3.0 cents per kWh surcharge. Although
the increase was authorized immediately, the 3.0 cents per kWh surcharge would
not be collected in rates until the CPUC established an appropriate rate design
for the surcharge, which was adopted on May 15, and implemented on June 1, 2001.
The actual surcharge that went into effect on June 1, 2001 was 3.5 cents per
kWh, of which 0.5 cents per kWh amortizes the under-collection accrued between
March 27, 2001, and the June 1, 2001 implementation date. The revenue generated
by the rate increase is to be used only for power procurement costs that are
incurred after March 27, 2001. The CPUC declared that the revenues generated by
this surcharge are subject to refund (1) if not used to pay for such power
purchases, (2) to the extent that generators and sellers of power make refunds
for over-collections, or (3) to the extent any administrative body or court
denies the refunds of over-collections in a proceeding where recovery has been
hampered by a lack of cooperation from the Utility. The 3.0 cents per kWh
surcharge is in addition to the emergency interim surcharge approved on January
4, 2001, which the CPUC made permanent in this decision. The CPUC also modified
accounting rules in response to a proposal made by TURN as described below.
Also, on March 27, 2001, the CPUC issued a decision ordering the Utility and the
other California investor-owned utilities to pay the DWR a per-kWh price equal
to the applicable generation-related retail rate per kWh established for each
utility, for each kWh that the DWR sells to the customers of each utility. The
CPUC determined that the generation-related component of retail rates should be
equal to the total bundled electric rate (including the 1.0 cent per kWh interim
surcharge adopted by the CPUC on January 4, 2001) 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 Utility's company-wide average generation-related rate
component is 6.471 cents per kWh before June 1, 2001. On June 1, 2001, the CPUC
adopted an additional rate surcharge of 3.516 cents per kWh. The CPUC ordered
the utilities to pay the DWR within 45 days after the DWR supplies power to
their retail customers, subject to penalties for each day that payment is late.
For power supplied through May 31, 2001, the amount of power scheduled to retail
end-use customers after March 27, 2001, for which the DWR is entitled to be
paid, would be based on the product of the number of kWh that the DWR scheduled
to the Utility 45 days earlier and the Utility's company-wide average
generation-related rate of 6.471 cents per kWh, as ordered by the CPUC. For
power scheduled to the Utility after June 1, 2001, the Utility began remitting
to the DWR in the more precise manner as outlined in the CPUC decision discussed
above.
In addition, on April 3, 2001, the CPUC adopted a method to calculate the CPA,
as described in Public Utilities Code Section 360.5 (added by AB 1X effective
February 1, 2001). Section 360.5 requires the CPUC to determine (1) the portion
of each electric utility's electric retail rate effective on January 5, 2001,
that is equal to the difference between the generation-related component of the
utility's retail rate in effect on January 5, 2001, and the sum of the costs of
the utility's own generation, QF contracts, existing bilateral contracts (i.e.,
entered into before February 1, 2001), and ancillary services, and (2) the
amount of the CPA that is allocable to the power sold by the DWR. The CPUC
decided that the CPA should be a set rate calculated by determining each
21
utility's generation-related revenues (for the Utility the CPUC has proposed
that this be equal to 6.471 cents per kWh multiplied by total kWh sales by the
Utility to the Utility's retail customers), then subtracting the result by each
utility's total kWh sales. Each utility's CPA rate will be used to determine
the amount of bonds the DWR may issue.
Using the CPUC's methodology, but substituting the CPUC's cost assumptions with
actual expected costs and including costs the CPUC has refused to recognize, the
Utility's calculations show that the CPA for the 11-month period February
through December 2001 would be negative by $2.2 billion, (i.e., there would be
no CPA available to the DWR) assuming the DWR purchases 84% of the Utility's net
open position. If AB 1X were amended to also include in the CPA all the
incremental revenue from the 3.0 cent per kWh increase discussed above
(approximately $2.3 billion for 11 months), then the amount available to the DWR
for the CPA for the comparable 11-month period, assuming the Utility were
allowed to recover its costs first, would be approximately $100 million. The
Utility believes the method adopted by the CPUC is unlawful and inconsistent
with Section 360.5 because, among other reasons, it establishes a set rate that
does not reflect actual residual revenues, overstates the CPA by excluding
and/or understating authorized costs, and to the extent it is dedicated to the
DWR does not allow the Utility to recover its own revenue requirements and costs
of service. The Utility's application for rehearing of this decision has been
denied.
Initially, the DWR advised the CPUC that its revenue requirement for the DWR's
power purchases was $4.715 billion and has asked the CPUC to establish specific
rates payable to the DWR to collect that revenue requirement as authorized by AB
1X. The DWR's stated revenue requirement is greater than the revenues that would
be provided by the 3.0 cent surcharge. Unless the CPUC increases rates to
provide sufficient revenues for the DWR to recover its revenue requirement, none
of the revenues from the 3.0 cent surcharge will be available to the Utility to
recover its procurement costs incurred after March 27, 2001 (including any ISO
charges for which the DWR disclaims responsibility).
On July 23, 2001, the DWR filed information concerning its revenue requirements
with the CPUC. The DWR stated that it seeks to collect $13.072 billion from
electric customers for the period January 17, 2001 through December 2002. Of
this amount, the DWR seeks to collect approximatewly $5.2 billion from the
Utility's customers. The Utility is required currently to pay the DWR
approximately $0.10 per kWh for each kWh provided by the DWR, including all of
the 3.0cent surcharge approved by the CPUC in March 2001. The DWR's filing
indicated that the average cost it is seeking from California utility customers
is 10.8 cents per kWh for 2001 and 13.7 cents per kWh in 2002. On July 24,
2001, the Utility requested that the DWR hold a public hearing on its revised
revenue requirement because the DWR's filing lacked sufficient detail to
determine the impact its revenue requirements may have on ratepayers and the
Utility.
In March 2001, the CPUC also adopted TURN's proposal to transfer on a monthly
basis the balance in each utility's TRA to the utilities' 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 that the utilities
restate and record their generation memorandum account balances to the TRA on a
monthly basis before any transfer of generation revenues to the TCBA. The CPUC
22
found that based on the accounting changes, the conditions for meeting the end
of the rate freeze have not been met.
The Utility believes the adoption of TURN's proposed accounting changes results
in illegal retroactive ratemaking, constitutes an unconstitutional taking of the
Utility's property, and violates the federal filed rate doctrine. The Utility
also believes the other CPUC decisions are similarly illegal to the extent they
would compel the Utility to make payments to the DWR and QFs without providing
adequate revenues for such payments. The Utility filed an application for
rehearing of this decision. The Utility also requested the Bankruptcy Court to
enjoin the CPUC from requiring the Utility to implement the regulatory
accounting changes.
On June 1, 2001, the Bankruptcy Court issued a decision denying the Utility's
request and granting the CPUC's motion to dismiss the complaint. The Utility
has filed an appeal of the Bankruptcy Court's order. The Utility will continue
to pursue all legal challenges to this unlawful CPUC decision.
Qualifying Facilities Contracts
In early 2001, the Utility had been paying only 15% of amounts due QFs. 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. On March
27, 2001, the CPUC issued a decision requiring the Utility and the other
California investor-owned utilities to pay QFs fully for energy deliveries made
on and after the date of the decision, within 15 days of the end of the QFs'
billing period. The decision permits QFs to establish a 15-day billing period
as compared to the current monthly period. The CPUC noted that its change to
the payment provision was required to maintain energy reliability in California
and thus provided that failure to make a required payment would result in a fine
in the amount owed to the QFs. The decision also adopts a revised pricing
formula relating to the California border price of gas applicable to energy
payments to all QFs, including those that do not use natural gas as a fuel.
Based on the Utility's preliminary review of the decision, the revised pricing
formula would reduce the Utility's 2001 average QF energy and capacity payments
from approximately 12.7 cents per kWh to 12.3 cents per kWh. Since May 2001,
the QFs under contract to the Utility are being paid in full for power purchased
since early April 2001.
In July 2001, the Utility signed five-year agreements with 131 of its QFs,
ensuring the Utility and its customers receive a reliable supply of electricity
at an average energy price of 5.37 cents per kilowatt-hour. Under the terms of
the agreements, the Utility will assume the QF contracts and pay the pre-
petition debt on these 131 QF contracts, totaling $740 million, on the effective
date of the plan of reorganization. The total amount the company owed to QFs
when it filed for Chapter 11 was approximately $1 billion. The agreements
represent 75% 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
of reorganization 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 U.S Bankruptcy Court. Most
of the agreements have already been approved, and the Utility will be making
filings for the remainder in the near future.
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Bilateral Contracts
Under the terms of AB 1890, the Utility was required to purchase all of its
power from the PX and ISO to meet the needs of its customers. On August 3,
2000, after the California energy crisis had begun, the CPUC approved the
Utility's use of bilateral contracts, subject to the Utility reaching agreement
with the CPUC on reasonableness standards. After two months of unsuccessful
discussions with the CPUC, on October 16, 2000, the Utility filed an advice
letter seeking CPUC approval of specific reasonableness standards in order to
expedite implementation of the August 3, 2000 decision. In spite of the
Utility's efforts, the CPUC has not adopted reasonableness standards
implementing the August 3, 2000 decision.
In October 2000, the Utility entered into multiple bilateral contracts with
suppliers for long-term electricity deliveries. Some of these contracts were
terminated by the counterparties who were entitled to do so in the event of a
the decline in the Utility's credit quality to below investment grade, certain
of these contracts were terminated by the counterparties. 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 $405 million. Two others are in negotiations and have combined
estimated market values at termination date that ranges from $126 million to
$217 million. The settled contract and lower end of the range of market values
for the contracts under negotiation total $552 million and have been recognized
as a reduction to the Cost of Electric Energy in the Consolidated Statement of
Operations. As of June 30, 2001, remaining individual contracts range in size
from approximately 61,200 MWhs to 3,504,000 MWhs of supply annually. The
contracts extend to 2003.
PX Energy Credits
In accordance with CPUC regulations, the Utility provides a PX energy credit to
those customers (known as direct access customers) who have chosen to buy their
electric energy from an energy service provider (ESP) other than the Utility.
As wholesale power prices began to increase beginning in June 2000, the level of
PX credits issued to direct access customers increased correspondingly to the
point where the credits exceeded the Utility's distribution and transmission
charges to direct access customers. For the six months ended June 30, 2001, the
PX credits reduced electric revenue by $80 million. The Utility ceased paying
most of these credits in December 2000, and as of June 30, 2001, the total of
accumulated credits for direct access customers that have not been paid by the
Utility is approximately $513 million. The actual amount that will be refunded
to ESPs will be dependent upon when the rate freeze ends and whether there are
any adjustments made to wholesale energy prices by the FERC.
Generation Valuation
Under the California electric industry restructuring legislation, the 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 transition
costs.
In August 2000, the Utility and a number of interested parties filed an
application with the CPUC requesting that the CPUC approve a settlement
agreement reached by these parties. The agreement was filed in the Utility's
proceeding to determine the market value of the hydroelectric generation assets.
In this settlement agreement, the Utility indicated that it would transfer its
hydroelectric generation assets, at a negotiated value of $2.8 billion, to an
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affiliate. Due to the high wholesale prices and the corresponding increase in
the value of its hydroelectric generation assets, in November 2000, as part of
an application with the CPUC seeking approval of a five-year RSP, the Utility
withdrew its support from the settlement agreement, eliminating it from
consideration in the proceeding.
In December 2000, the Utility submitted updated testimony in the hydroelectric
valuation proceeding indicating the market value of the hydroelectric assets
ranges from $3.9 billion to $4.2 billion assuming a competitive auction or other
arms-length sale.
In the December 15, 2000 FERC order, the FERC ordered that ratemaking for the
Utilty's remaining generation be returned to the jurisdiction of the CPUC. In
January 2001, California Assembly Bill 6 was passed which prohibits disposal of
any of the Utility's generation facilities, including the hydroelectric
facilities, before January 1, 2006. At June 30, 2001, the book value of the
Utility's net investment in hydroelectric generation assets was approximately
$585 million.
On June 15, 2001, the Utility filed testimony in its RSP proceeding to present
its revenue requirement for cost-based rates for its retained generation,
including its hydroelectric and nuclear facilities, qualifying facilities,
bilateral contracts, and ancillary services. The Utility argued that the revenue
requirements for its hydroelectric facilities should be based on a market
valuation of its hydroelectric assets, as required by current law, at a minimum
value of $4.1 billion. Based on this valuation, the Utility argued that its
rate freeze ended as early as April 2000, notwithstanding the implementation of
the retroactive changes to the transition period ratemaking mechanisms discussed
above. Combined with the revenue requirements for other retained generation and
purchase power costs, the Utility proposed a 2001 revenue requirement of $6.7
billion. The Utility was directed by the CPUC to present other revenue
requirement scenarios. These alternate scenarios produce 2001 revenue
requirements between $3.9 billion based on the amount of unrecovered capital
costs at April 30, 2001 and assuming the rate freeze ended before January 1,
2001, to $9.9 billion which amount assumes the rate freeze has not ended. It is
likely that the CPUC will not act on the Utility's 2001 revenue requirement
filing until after the CPUC acts on the DWR's revenue requirement. In such
event, it is uncertain whether current rates as they may be apportioned between
the Utility and the DWR will be sufficient for the Utility to recover the
revenue requirements that may eventually be adopted by the CPUC.
Diablo Canyon Benefits Sharing
As required by a prior CPUC decision, on June 30, 2000, the Utility filed an
application with the CPUC requesting approval of its proposal for sharing with
ratepayers 50% of the post-rate freeze net benefits of operating Diablo Canyon.
The net benefit sharing methodology proposed in the Utility's application would
be effective at the end of the current electric rate freeze for the Utility's
customers and would continue for as long as the Utility owned Diablo Canyon.
Under the proposal, the Utility would share the net benefits of operating Diablo
Canyon based on the auditedprofits from operations, determined consistent with
the prior CPUC decisions. If Diablo Canyon experiences losses, such losses
would be deferred and netted against profits in the calculation of the net
benefits in subsequent periods (or against profits in prior periods if
subsequent profits are insufficient to offset such losses). Any changes to the
net sharing methodology must be approved by the CPUC. The CPUC has suspended
the proceedings to consider the net benefit-sharing proposal. In the Utility's
RSP, parties have proposed that the requirement to establish a sharing
methodology be rescinded and the Diablo Canyon be placed on cost-of-service
ratemaking. In the Utility's June 15, 2001 revenue requirement testimony in its
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rate stabilization proceedings, the Utilty proposed that the revenue
requirements for Diablo Canyon should reflect the 50/50 sharing of net benefits
between shareholders and ratepayers using a market revenue benchmark and actual
ongoing costs. It is uncertain what future ratemaking will be applicable to
Diablo Canyon.
Note 3: VOLUNTARY PETITION FOR RELIEF UNDER CHAPTER 11
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, discussed further in Note 2) 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. These claims are reflected in the June 30, 2001,
balance sheet 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 and by pledged accounts receivable from gas
customers. The Bankruptcy Court has approved making the regular interest
payments on the Utility's secured debt.
A creditors' committee has been appointed as an official committee and, in
accordance with the provisions of the Bankruptcy Code, will have the right to be
heard on all matters that come before the Bankruptcy Court. The Utility expects
that the creditors' committee will play an important role in the negotiation of
the terms of any plan of reorganization.
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 for approximately $1.5 billion in capital expenditures for on-going
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 January 10, 2001, the Utility suspended the payment of its fourth quarter
2000 common stock dividend of $109 million, declared in October 2000, to PG&E
Corporation and its wholly owned subsidiary PG&E Holdings, LLC Until its
financial condition is restored, the Utility is precluded from paying common
stock dividends to PG&E Corporation and PG&E Holdings, LLC In addition, the
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Utility's Board of Directors did not declare the regular preferred stock
dividends for the three-month period ended January 31, 2001, or for the three-
month period ended April 30, 2001. Dividends on all Utility preferred stock are
cumulative. Until cumulative dividends on 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.
In July 2001, the Bankruptcy Court granted a motion that the Utility had filed
requesting that the court extend until December 6, 2001, the period during which
the Utility has the exclusive right to file a plan of reorganization in its
Chapter 11 case. Under the normal timeline, the exclusivity period would have
ended on August 6, 2001, 120 days after the Utility's April 6, 2001, Chapter 11
filing. The Utility filed for an extension of the exclusivity period in the
event that additional time is needed to continue discussions with creditors and
to develop and file a comprehensive and feasible plan of reorganization. The
Bankruptcy Court may confirm a plan of reorganization only upon making certain
findings required by the Bankruptcy Code, and a plan may be confirmed over the
dissent of non-accepting creditors and equity security holders if certain
requirements of the Bankruptcy Code are met. The payment rights and other
entitlements of pre-petition creditors and the Utility's shareholders may be
substantially altered by any plan of reorganization confirmed by the Bankruptcy
Court. Although it is the Utility's intent to pay all valid claims, pre-
petition creditors may receive, under a plan, less than 100% of the face value
of their claims, and the interests of the Utility's equity security holders may
be affected. A plan of reorganization could materially change the amounts and
classification reported in the consolidated financial statements.
The Utility is not able at this time to predict the outcome of its bankruptcy
case, the terms and provisions of any plan of reorganization, 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 equity 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.
NOTE 4: PRICE RISK MANAGEMENT
PG&E Corporation's net gain (loss) on trading contracts for the three- and six-
month periods ended June 30, 2001 are $93 million and $121 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 six-month periods
ended June 30, 2001. PG&E Corporation's and the Utility's estimated net
derivative gains or losses included in accumulated other comprehensive income
(loss) at June 30, 2001 that are expected to be reclassified into earnings
within the next twelve months are net losses of $59 million and $38 million,
respectively. The actual amounts reclassified from accumulated other
comprehensive income (loss) to earnings can differ as a result of market price
changes. PG&E Corporation expects approximately $20 million of these net
derivative losses to be offset when the items being hedged are recognized in
earnings.
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The schedule below summarizes the activities affecting accumulated other
comprehensive loss from derivative instruments for the three- and six-month
periods ended June 30, 2001.
Three months ended Six months ended
June 30, 2001 June 30, 2001
----------------------- -----------------------
PG&E PG&E
(in millions) Corporation Utility Corporation Utility
----------- ------- ----------- -------
Beginning derivative gains (losses) included in
accumulated other comprehensive income (loss)
$ (315) $ (52) $ (243) $ 90
Net gain (loss) of current period
hedging transactions 178 (8) 149 (7)
Net gain (loss) reclassified to
earnings 31 19 (12) (124)
----- ----- ----- -----
Ending derivative gains (losses)
included in accumulated other
comprehensive income (loss) (106) (41) (106) (41)
Foreign currency translation
adjustment (3) (1) (3) (1)
----- ----- ----- -----
Ending accumulated other comprehensive
income (loss) at June 30, 2001 $ (109) $ (42) $ (109) $ (42)
===== ===== ===== =====
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
nonperformance by counterparties pursuant to the terms of their contractual
obligations. The counterparties 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 counterparties in accordance
with established credit approval practices and limits. PG&E Corporation
assesses the financial strength of its counterparties at least quarterly and
requires that counterparties post security in the forms 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 experienced a loss of approximately $9 million and $34 million
due to the nonperformance of counterparties during the three- and six-month
periods ended June 30, 2001, respectively. Counterparties considered to be
investment grade or higher comprise 84% of the total credit exposure. At June
30, 2001, PG&E Corporation's and the Utility's gross credit risk exposure
amounted to $1.1 billion and $142 million, respectively.
NOTE 5: UTILITY OBLIGATED MANDATORILY REDEEMABLE PREFERRED SECURITIES OF TRUST
HOLDING SOLELY UTILITY SUBORDINATED DEBENTURES
The Utility, through its wholly owned subsidiary, PG&E Capital I (Trust), has
outstanding 12 million shares of 7.90% 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
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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 beginning in 2000 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 Chapter 11 of the Bankruptcy Code. Pursuant to the Trust
Agreement, the bankruptcy filing by the Utility constitutes an Early Termination
Event. The 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.
NOTE 6: COMMITMENTS AND CONTINGENCIES
Nuclear Insurance
The Utility has insurance coverage for property damage and business interruption
losses as a member of Nuclear Electric Insurance Limited (NEIL). Under this
insurance, if a nuclear generating facility suffers a loss due to a prolonged
accidental outage, the Utility may be subject to maximum retrospective
assessments of $12 million (property damage) and $4 million (business
interruption), in each case per policy period, in the event losses exceed the
resources of NEIL.
The Utility has purchased primary insurance of $200 million for public liability
claims resulting from a nuclear incident. The Utility has secondary financial
protection, which provides an additional $9.3 billion in coverage, which is
mandated by federal legislation. It provides for loss sharing among utilities
owning nuclear generating facilities if a costly incident occurs. If a nuclear
incident results in claims in excess of $200 million, then the Utility may be
assessed up to $176 million per incident, with payments in each year limited to
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a maximum of $20 million per incident.
Workers' Compensation Security
On May 9, 2001, the Department of Industrial Relations approved the Utility's
security deposit of approximately $401 million in collateral provided by surety
bonds, providing backing for the Utility's status as a self-insured for workers'
compensation. This represents a decrease of approximately $55 million in
security from the previous year, reflecting a reduction in estimates of workers'
compensation obligations. These bonds are backed up by an indemnity at the PG&E
Corporation level.
The Utility has for several years utilized surety bonds as its method of
providing security (other forms of acceptable security include LOC's, cash, or
securities.) In February 2001, several of the surety bonds provided
cancellation notices, citing concerns about the Utility's financial situation.
However, under the state-developed bond form, the canceling sureties are not
released of their obligation for workers' compensation claims occurring before
the effective date of the cancellation until released by the State.
The State has continued to apply the canceled bond amounts totaling $185 million
towards the $401 million requirement. The Utility was able to supplement the
difference through three additional active surety bonds totaling $216 million.
This cancellation has not, to date, impacted the Utility's self-insured status
under California law, or its ability to meet current plan obligations.
Environmental Remediation
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 it 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 June 30, 2001, the Utility expects to spend $306 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
30
than anticipated, the Utility could spend as much as $459 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 $306 million and $320
million at June 30, 2001 and December 31, 2000, respectively. The $306 million
accrued at June 30, 2001 includes (1) $139 million related to the pre-closing
remediation liability, associated with the divested generation facilities
discussed further in the "Generation Valuation" section of Note 2, and (2) $167
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 $306 million environmental remediation liability, the Utility
has recovered $139 million through rates, and expects to recover another $86
million in future rates. The Utility is seeking recovery of the remainder of
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.
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. 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
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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.
PG&E Corporation believes the ultimate outcome of these matters will not have a
material impact on its or the Utility's financial position or results of
operations.
PG&E National Energy Group
The U.S. Environmental Protection Agency ("EPA") has been conducting a
nationwide enforcement investigation regarding the historical compliance of
coal-fueled electric generating stations with various permitting requirements of
the Clean Air Act. Specifically, the EPA and the U.S. Department of Justice
have recently initiated enforcement actions against a number of electric
utilities, several of which have entered into substantial settlements for
alleged Clean Air Act violations related to modifications (sometimes more than
20 years ago) of existing coal-fired generating facilities. In May 2000, PG&E
NEG received a request for information seeking detailed operating and
maintenance histories for the Salem Harbor and Brayton Point power plants and,
in November 2000, the EPA visited both facilities. PG&E NEG believes this
request for information is part of the EPA's industry-wide investigation of
coal-fired power plants' compliance with the Clean Air Act requirements
governing plant modifications. PG&E NEG also believes that any changes it made
to these plants were routine maintenance or repair and, therefore, did not
require permits. The EPA has not issued a notice of violation or filed any
enforcement action against PG&E NEG at this time. Nevertheless, if the EPA
disagrees with PG&E NEG's conclusions with respect to the changes PG&E NEG made
at the facilities, and successfully brings an enforcement action against PG&E
NEG, then penalties may be imposed and further emission reductions might be
necessary at these plants.
From time to time various states in which our facilities are located consider
the adoption of air emissions standards that may be more stringent than those
imposed by EPA. On May 11, 2001, the Massachusetts Department of Environmental
Protection (DEP) issued regulations imposing new restrictions on emissions of
NOx and SO2, mercury and carbon dioxide from existing coal-fired power plants.
These restrictions will impose more stringent annual and monthly limits on NOx
and SO2 emissions than currently exist and will take effect in stages, beginning
in October 2004 if no permits are needed for the changes necessary to comply,
and beginning in 2006 if such permits are needed. DEP has informed PG&E NEG
that, based upon its current understanding of the facilities' plans for
compliance with the new regulations, it believes that permits will be needed and
that the initial compliance date will therefore be 2006. However, the need for
permits triggers an obligation to meet Best Available Control Technology, or
BACT, requirements. Compliance with BACT at the facilities could require
implementation of controls beyond those otherwise necessary to meet the
emissions standards in the new regulations. Mercury emissions are capped as a
first step and must be reduced by October 2006 pursuant to standards to be
developed. Carbon dioxide emissions are regulated for the first time and must
be reduced from recent historical levels. PG&E NEG believes that compliance
with the carbon dioxide caps can be achieved through implementation of a number
of strategies, including sequestrations and offsite reductions. Various testing
and recordkeeping requirements are also imposed.
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By 2002, PG&E NEG plans to have approximately 5,100 MW of generating capacity in
operation in New England. The new Massachusetts regulations affect primarily
its Brayton Point and Salem Harbor generating facilities, representing
approximately 2,300 MW. Through 2006, it may be necessary to spend
approximately $265 million to comply with these regulations. In addition, with
respect to approximately 600 MW (or about 12%) of PG&E NEG's New England
capacity, PG&E NEG may need to implement fuel conversion, limit operations, or
install additional environmental controls. These new regulations require that
PG&E NEG achieve specified emission levels earlier than the dates included in a
previous Massachusetts initiative to which it had agreed.
The federal Clean Water Act generally prohibits the discharge of any pollutants,
including heat, into any body of surface water, except in compliance with a
discharge permit issued by a state environmental regulatory agency and/or EPA.
All of the facilities that are required to have such permits either have them or
have timely applied for extensions of expired permits and are operating in
substantial compliance with the prior permit. At this time, three of the
fossil-fuel plants owned and operated by PG&E NEG's affiliate USGen New England,
Inc. (Manchester Street, Brayton Point and Salem Harbor stations) are operating
pursuant to permits that have expired. For the facilities whose NPDES permits
have expired, permit renewal applications are pending, and we anticipate that
all three facilities will be able to continue to operate in substantial
compliance with prior permits until new permits are issued. It is estimated
that USGen New England's cost to comply with new permit conditions could be
approximately $60 million through 2005. It is possible that the new permits may
contain more stringent limitations than the prior permits.
PG&E NEG anticipates spending up to approximately $330 million, net of insurance
proceeds, through 2006 for environmental compliance at currently operating
facilities, which primarily addresses: (a) new Massachusetts air regulations
made public on April 23, 2001 affecting the Brayton Point and Salem Harbor
Stations; (b) wastewater permitting requirements that may apply to the Brayton
Point, Salem Harbor and Manchester Street Stations; and (c) requirements, to
which we agreed, that are reflected in a consent decree concerning wastewater
treatment facilities at the Salem Harbor and Brayton Point Stations.
During April 2000, an environmental group served an affiliate of PG&E NEG, USGen
New England, Inc., and other of its subsidiaries with a notice of its intent to
file a citizen's suit under RCRA. The group stated that it planned to allege
that USGen New England, as the generator of fossil fuel combustion wastes at
Salem Harbor and Brayton Point, has contributed and is contributing to the past
and present handling, storage, treatment and disposal of wastes at those
facilities which may present an imminent and substantial endangerment to the
public health or the environment. During September 2000, USGen New England
signed a series of agreements with the Massachusetts DEP and the environmental
group that address and resolve these matters. The agreements, which have been
filed in federal court and are now incorporated in a consent decree, require,
among other things, that USGen New England alter its existing wastewater
treatment facilities at both facilities by replacing certain unlined treatment
basins, submit and implement a plan for the closure of such basins, and perform
certain environmental testing at the facilities. Although the outcome of such
environmental testing could lead to higher costs, the total cost of these
activities is expected to be approximately $21 million, and they are underway.
33
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
- -------------------
Several civil suits are pending against the Utility in California State Court.
The suits seek an unspecified amount of compensatory and punitive damages for
alleged personal injuries resulting from alleged exposure to chromium in the
vicinity of the Utility's gas compressor stations at Hinckley, Kettleman, and
Topock, California. Currently, there are claims pending on behalf of
approximately 1,160 individuals.
The Utility is responding to the suits and asserting affirmative defenses. The
Utility will pursue appropriate legal defenses, including statute of
limitations, exclusivity of worker's compensation laws, and factual defenses,
including lack of exposure to chromium and the inability of chromium to cause
certain of the illnesses alleged. The Utility has recorded a legal 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.
Wilson vs. PG&E Corporation and Pacific Gas and Electric Company
- ----------------------------------------------------------------
On February 13, 2001, two complaints were filed against PG&E Corporation and the
Utility in the Superior Court of the State of California, San Francisco 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).
In Wilson I, the plaintiff alleges that in 1998 and 1999, PG&E Corporation
violated its fiduciary duties and California Business and Professions Code
Section 17200 by causing the Utility to repurchase shares of the Utility's
common stock from PG&E Corporation at an aggregate price of $2,326 million. The
complaint alleges an unlawful business act or practice under Section 17200
because these repurchases allegedly violated PG&E Corporation's fiduciary
duties, a first priority capital requirement allegedly imposed by the CPUC's
decision approving the formation of a holding company, and also an implicit
public trust imposed by AB 1890, which granted authority for the issuance of
rate reduction bonds. The complaint seeks to enjoin the repurchase by the
Utility of any more of its common stock from PG&E Corporation or other entities
or persons unless good cause is shown, and seeks restitution from PG&E
Corporation of $2,326 million, with interest, on behalf of the Utility. The
complaint also seeks an accounting, costs of suit, and attorney's fees.
In Wilson II, the plaintiff alleges that PG&E Corporation, the Utility, and
other subsidiaries have been parties to a tax-sharing arrangement under which
PG&E Corporation annually files consolidated federal and state income tax
returns for, and pays, the income taxes of PG&E Corporation and participating
subsidiaries. According to the plaintiff, between 1997 and 1999, PG&E
Corporation collected $2,957 million from the Utility under this tax-sharing
agreement. Plaintiff alleges that these monies were held under an express and
implied trust to be used by PG&E Corporation to pay the Utility's share of
income taxes under the tax-sharing arrangement. Plaintiff alleges that PG&E
Corporation overcharged the Utility $663 million under the tax-sharing
34
arrangement and has declined voluntarily to return these monies to the Utility,
in violation of the alleged trust, the alleged first priority capital condition,
and California Business and Professions Code Section 17200. The complaint seeks
to enjoin PG&E Corporation from engaging in the activities alleged in the
complaint (including the tax-sharing arrangement), and seeks restitution from
PG&E Corporation of $663 million, with interest, on behalf of the Utility. The
complaint also seeks an accounting, costs of suit, and attorney's fees.
PG&E Corporation's and the Utility's analysis of these complaints is at a
preliminary stage, but PG&E Corporation and the Utility believe them to be
without merit and intend to present a vigorous defense. The Utility filed
notice of automatic stay on April 11, 2001, pursuant to the Bankruptcy Code. On
April 19, 2001, the court signed stipulations between PG&E Corporation and
plaintiffs to stay all proceedings in the cases as against PG&E Corporation.
PG&E Corporation and the Utility are unable to predict whether the outcome of
this litigation, if it were to proceed, will have a material adverse effect on
their financial condition or results of operation.
Federal Securities Lawsuit
- --------------------------
A complaint, Gillam, et al v. PG&E Corporation and Pacific Gas and Electric
ompany, et al, is pending in the U.S. District Court for the Northern District
of California. The complaint alleges that PG&E Corporation and the Utility
violated federal securities laws, generally accepted accounting principles, and
other regulations or accounting rules, by issuing allegedly false and misleading
financial statements in the second and third quarters of 2000, reporting net
income of $753 million for the nine-month period ending September 30, 2000,
instead of an alleged net loss for that period of up to $2.1 billion. According
to the complaint, defendants failed to properly account in the second and third
quarters of 2000 for alleged under-collected power purchase costs and PG&E
Corporation announced in March 2001 that it intended to take a $4.1 billion
write-off. Plaintiff purports to bring the action individually and on behalf of
a class of individuals who purchased PG&E Corporation's common stock during the
period from June 1, 2000, to March 31, 2001, claiming that the alleged
misrepresentations caused them to pay inflated prices for the stock. Plaintiff
seeks damages in excess of $2.4 billion, punitive damages, interest, injunctive
relief, and attorneys' fees.
The complaint was filed after the Utility filed for reorganization under Chapter
11 of the U.S. Bankruptcy Code. The Utility informed plaintiff that the action
is stayed by the automatic stay provisions of the Bankruptcy Code and on or
about April 23, 2001, plaintiff filed a notice of voluntary dismissal without
prejudice with respect to the Utility.
Analysis of the complaint by PG&E Corporation is at a preliminary stage, but
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.
PG&E National Energy Group
PG&E NEG is involved in various litigation matters in the ordinary course of its
business. PG&E NEG is not currently involved in any litigation that is
expected, either individually or in the aggregate, to have a material adverse
effect on financial condition or results of operations of PG&E Corporation.
35
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
provisions are reviewed quarterly and adjusted to reflect the impacts of
negotiations, settlements, rulings, advice of legal counsel, and other
information and events pertaining to a particular case. The following table
reflects the current year's activity to the recorded liability for legal
matters:
PG&E
Corporation
and Utility
(in millions) -----------
Beginning balance, January 1, 2001 $185
Provisions for liabilities 4
Payments (2)
Adjustments (3)
---
Ending balance, June 30, 2001 $184
===
NOTE 7: 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 generally accepted accounting principles, 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 National Energy Group
PG&E Corporation's subsidiary, 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 has been renamed PG&E Integrated Energy and Marketing (PG&E Energy),
36
which includes PG&E Generating Company, LLC and its affiliates, PG&E Energy
Trading Holdings Corporation which owns PG&E Energy Trading-Power, L.P., PG&E
Energy Trading-Gas Corporation, and their affiliates, and PG&E Interstate
Pipeline Operations (PG&E Pipeline), which includes PG&E Gas Transmission
Corporation and its affiliates which includes PG&E Gas Transmission
Northwest(PG&E GTN), PG&E Gas Transmission, Texas Corporation, and PG&E Gas
Transmission Teco, Inc., and their subsidiaries. During the fourth quarter of
2000, PG&E NEG sold its Texas natural gas and natural gas liquids business
operated through PG&E Gas Transmission, Texas Corporation and PG&E Gas
Transmission Teco, Inc. and their subsidiaries. Also during 2000, PG&E NEG sold
its energy services unit, PG&E Energy Services Corporation.
37
Segment information for the three and six months ended June 30, 2001, and 2000
was as follows:
PG&E National Energy Group
PG&E
Integrated Interstate Corporation
Energy and Pipeline NEG & other
(in millions) Utility Total NEG Marketing Operations Eliminations Eliminations (2) Total
------ -------- ----------- ---------- ----------- --------------- -----
Three months ended June 30, 2001
Operating revenues $ 2,305 $ 2,708 $ 2,640 $ 55 $ 13 $ - $ 5,013
Intersegment revenues (1) 4 48 39 9 - (52) -
------ ------ ------ ----- ----- ------ ------
Total operating revenues 2,309 2,756 2,679 64 13 (52) 5,013
Net Income (Loss) 696 71 53 19 (1) (17) 750
Three months ended June 30, 2000(4)
Operating revenues 2,293 3,345 3,086 267 (8) - 5,638
Intersegment revenues(1) 3 17 4 13 - (20) -
----- ----- ----- ----- ----- ------ ------
Total operating revenues 2,296 3,362 3,090 280 (8) (20) 5,638
Net income 216 32 18 13 1 - 248
Six months ended June 30, 2001
Operating revenues 4,865 6,823 6,708 111 4 - 11,688
Intersegment revenues (1) 6 141 123 18 - (147) -
------ ------ ------- ------ ----- ------ -------
Total operating revenues 4,871 6,964 6,831 129 4 (147) 11,688
Net Income (Loss) (304) 125 88 38 (1) (22) (201)
Total assets at June 30, 2001(3)
23,216 11,957 10,310 1,172 475 223 35,396
Six months ended June 30, 2000(4)
Operating revenues 4,507 6,139 5,601 537 1 - 10,646
Intersegment revenues (1) 7 55 30 25 - (62) -
------ ------ ------ ----- ----- ------ ------
Total operating revenues 4,514 6,194 5,631 562 1 (62) 10,646
Net Income (Loss) 444 84 56 27 1 - 528
Total assets at June 30, 2000(3)
$22,124 $ 9,248 $ 6,853 $2,080 $315 $(143) $31,229
(1) Inter-segment electric and PG&E 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 "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.
38
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 the provisions of Chapter 11 of the
U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, 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. 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 has been renamed PG&E Integrated
Energy and Marketing (PG&E Energy), which includes PG&E Generating Company, LLC
and its affiliates, and PG&E Energy Trading Holdings Corporation which owns PG&E
Energy Trading-Power, L.P., PG&E Energy Trading-Gas Corporation, and their
affiliates, and PG&E Interstate Pipeline Operations (PG&E Pipeline), which
includes PG&E Gas Transmission Corporation, PG&E Gas Transmission Northwest
Corporation (PG&E GTN), PG&E Gas Transmission, Texas Corporation and PG&E Gas
Transmission Teco, Inc. and their subsidiaries. During the fourth quarter of
2000, PG&E NEG sold its Texas natural gas and natural gas liquids business
operated through PG&E Gas Transmission, Texas Corporation and PG&E Gas
Transmission Teco, Inc. and their subsidiaries. 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 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-K.
This combined Quarterly Report on Form 10-Q, including this MD&A, contains
forward looking statements about the future that are necessarily subject to
various risk and uncertainties. In addition, PG&E Corporation expects that its
net income from operations for 2001 will be in the range of $2.70-$2.75 per
share. 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
39
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;
- - whether and to what extent the Utility is determined to be responsible for
the Independent System Operator's (ISO) charges billed to the Utility;
- - the extent to which more information is revealed about the recently released
California Department of Water Resources' revenue requirements and the impact
such revenue requirements may have on the Utility's financial condition and
results of operation;
- - the terms and conditions of the reorganization plan that is ultimately
adopted by the Bankruptcy Court and the extent to which the Utility's bankruptcy
proceedings affect the operations of PG&E Corporation's other businesses;
- - 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 method and timing of valuation 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;
- - 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 and economic conditions;
- - the extent to which our current or planned generation, pipeline, and storage
capacity development projects of PG&E NEG, a wholly owned subsidiary of PG&E
Corporation, 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 riskssuch
as PG&E NEG's failure to obtain financing, 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;
40
- - PG&E NEG's ability to obtain financing for its planned development projects
and its ability to refinance PG&E NEG's and its subsidiaries' existing
indebtedness on reasonable terms;
- - 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.
In this MD&A, we first discuss the California energy crisis and its impact on
our liquidity. We then discuss statements of cash flows and financial
resources, and our results of operations for the three and six-month periods
ended June 30, 2001 and 2000. Finally, we discuss our competitive and
regulatory environment, our risk management activities, and various
uncertainties that could affect future earnings. Our MD&A applies to both PG&E
Corporation and the Utility.
LIQUIDITY AND FINANCIAL RESOURCES
The California Energy Crisis
The state of California is in the midst of an energy crisis. The cost of
wholesale power has risen dramatically since June 2000. Rolling blackouts have
occurred as a result of a broken deregulated electricity market. Because of
this crisis, PG&E Corporation and the Utility have experienced a significant
deterioration in their liquidity and consolidated financial position. The
Utility's credit rating has deteriorated to below investment grade level. PG&E
Corporation and the Utility recognized a fourth quarter charge to earnings of
$6.9 billion ($4.1 billion after tax) to reflect the fact that the Utility could
no longer conclude that its generation-related regulatory assets and under-
collected purchased power costs were probable of recovery from ratepayers. In
addition, during the first quarter of 2001, the Utility recognized after tax
charges of $1.1 billion representing under-collected power costs incurred during
that period. These charges resulted in accumulated deficits at March 31, 2001,
of $3 billion for both the Utility and PG&E Corporation.
As more fully discussed herein, the Utility had been working with regulators and
state and federal legislators and California political leaders in an effort to
seek an overall solution to the California energy crisis. However, the ongoing
uncertainty as to the timing and extent of any solution, in addition to
increasing debt and regulatory changes, caused the Utility to seek protection
from its creditors through a Chapter 11 Bankruptcy Filing. The filing for
bankruptcy protection and the related uncertainty around any reorganization
plan, that is ultimately adopted, will have a significant impact on the
Utility's future liquidity and results of operations. See Notes 2 and 3 of the
41
Notes to the Condensed Consolidated Financial Statements for a detailed
discussion of the California Energy Crisis and the events leading up to the
charge incurred by PG&E Corporation and the Utility. A discussion of the
current and future liquidity and financial resources, and mitigation efforts
undertaken by the Utility and PG&E Corporation follows.
Pacific Gas and Electric Company
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 18.2 cents per kilowatt-hour (kWh) for the seven-month period of June
2000 through December 2000, as compared to an average cost of 4.2 cents per kWh
for the same period in 1999. Under California Assembly Bill 1890 (AB 1890), the
Utility's electric rates were frozen at levels that allowed approximately 5.4
cents 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, and rose to approximately $8.5 billion
by March 31, 2001.
The difference between the actual costs incurred to purchase power and the
amount recovered from customers was funded through a series of borrowings. In
October 2000, the Utility fully utilized its existing $1 billion revolving
credit facility to support the Utility's commercial paper program and other
liquidity requirements. On October 18, 2000, the Utility obtained an additional
$1 billion, 364-day revolving credit facility to support the issuance of
additional commercial paper. On November 1, 2000, the Utility issued $1 billion
of short-term floating rate notes and $680 million of five-year notes. On
November 22, 2000, the Utility issued an additional $240 million of short-term
floating rate notes. On December 1, 2000, the size of the $1 billion, 364-day
revolving credit facility was reduced to $850 million in order to comply with
the syndication agreement. At December 31, 2000, the Utility had borrowed $614
million against its five-year revolving credit agreement, had issued $1,225
million of commercial paper, and had issued $1,240 million of floating rate
notes.
In response to the growing crisis, on January 4, 2001, the California Public
Utilities Commission (CPUC) approved an interim 1.0 cent per kWh rate increase,
which would raise approximately $70 million in cash per month for three months.
Even if all this cash had been available to the Utility immediately, $210
million represented approximately one week's worth of net power purchases at the
then-current prices. Thus, the rate increase did not raise enough cash for the
Utility to pay its ongoing wholesale electric energy procurement bills or make
further borrowing possible.
On January 10, 2001 the Board of Directors of the Utility suspended the payment
of its fourth quarter 2000 common stock dividend in an aggregate amount of $110
million payable on January 18, 2001, to PG&E Corporation and PG&E Holdings, LLC,
a wholly owned subsidiary of the Utility. In addition, the Utility's Board of
Directors decided not to declare the regular preferred stock dividends for the
three-month period ended January 31, 2001, normally payable on February 15,
2001. Dividends on all Utility preferred stock are cumulative. Until
cumulative dividends on 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.
On January 16 and 17, 2001, the outstanding bonds of the Utility were downgraded
42
to below-investment grade status. Standard and Poor's (S&P) stated that the
downgrade reflected the heightened probability of the Utility's imminent
insolvency and the resulting negative financial implications for the PG&E
Corporation and affiliated companies because, among other reasons, (1) some of
the Utility's principal trade creditors were demanding that sizeable cash
payments be made as a pre-condition for the purchase of natural gas and electric
power necessary for on-going business operations; (2) neither legislative nor
negotiated solutions to the California utilities' financial situation appeared
to be forthcoming in a timely manner, which continued to impede access to
financial markets for the working capital needed to avoid insolvency; and (3)
Southern California Edison's (SCE) decision to default on its obligation to pay
principal and interest due on January 16, 2001, diminished the prospects for the
Utility's access to capital markets.
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 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. Under the Act, the state
must pay the Utility the reasonable value of the contracts, although the PX may
seek to recover the monies that the Utility owes to the PX from any proceeds
realized from those contracts. Discussions and negotiations on this issue are
currently ongoing between the state and the Utility. The Utility has recently
filed a complaint against the state to recover the value of the seized
contracts.
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. Assembly Bill 1X (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.
As previously stated, beginning in June 2000, the Utility experienced
unanticipated and massive increases in the wholesale costs of the electricity
purchased from the PX and ISO on behalf of its retail customers. 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 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
43
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, 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 statement. On June
13, 2001, the FERC denied the ISO's request for rehearing of its April 6, 2001
order.
The Utility has 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 counterparty, 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. The Utility believes that its only responsibility for third
party power delivered to its customers is to pay the DWR the amount collected
from customers, whether the third party power is purchased by a creditworthy
buyer or whether the purchase is facilitated by a creditworthy counterparty.
As a result of (1) the failure, at the time of filing, by the state to assume
the full procurement responsibility for the Utility's net open position, as was
provided under AB 1X, (2) the negative impact of recent actions by the CPUC that
created new payment obligations for the Utility and undermined its ability to
return to financial viability, (3) a lack of progress in negotiations with the
state to provide a solution for the energy crisis, and (4) 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 Chapter 11 of the U.S.
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, discussed further in Note 2)
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. These claims are reflected in the June 30, 2001,
balance sheet 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 proceeding.
44
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.
A creditors' committee has been appointed as an official committee and, in
accordance with the provisions of the Bankruptcy Code, will have the right to be
heard on all matters that come before the Bankruptcy Court. The Utility expects
that the creditors' committee will play an important role in the negotiation of
the terms of any plan of reorganization.
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 for approximately $1.5 billion in capital expenditures for on-going
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 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 its wholly owned subsidiary PG&E Holdings, LLC Until its
financial condition is restored, the Utility is precluded from paying common
stock dividends to PG&E Corporation and PG&E Holdings, LLC In addition, the
Utility's Board of Directors did not declare the regular preferred stock
dividends for the three-month period ended January 31, 2001, or for the three-
month period ended April 30, 2001. Dividends on all Utility preferred stock are
cumulative. Until cumulative dividends on 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.
In July 2001, the Bankruptcy Court granted a motion that the Utility had filed
requesting that the court extend until December 6, 2001, the period during which
the Utility has the exclusive right to file a plan of reorganization in its
Chapter 11 case. Under the normal timeline, the exclusivity period would have
ended on August 6, 2001, 120 days after the Utility's April 6, 2001, Chapter 11
filing. The Utility filed for an extension of the exclusivity period in the
event that additional time is needed to continue discussions with creditors and
to develop and file a comprehensive and feasible plan of reorganization. The
Bankruptcy Court may confirm a plan of reorganization only upon making certain
findings required by the Bankruptcy Code, and a plan may be confirmed over the
dissent of non-accepting creditors and equity security holders if certain
requirements of the Bankruptcy Code are met. The payment rights and other
entitlements of pre-petition creditors and the Utility's shareholders may be
substantially altered by any plan of reorganization confirmed by the Bankruptcy
Court. Although it is the Utility's intent to pay all valid claims, pre-
petition creditors may receive, under a plan, less than 100% of the face value
of their claims, and the interests of the Utility's equity security holders may
be affected. A plan of reorganization could materially change the amounts and
classification reported in the consolidated financial statements.
The Utility is not able at this time to predict the outcome of its bankruptcy
case, the terms and provisions of any plan of reorganization, 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.
45
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.
Commencing 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 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 $272 million at
June 30, 2001, and believes that the funds will be adequate to maintain its
continuing operations throughout 2001. In addition, PG&E Corporation believes
that the holding company and its non-CPUC regulated subsidiaries are protected
from the bankruptcy of the Utility.
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
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.
PG&E Corporation Consolidated
Net cash provided by PG&E Corporation's operating activities totaled $697
million and $1,675 million for the six months ended June 30, 2001 and 2000,
respectively. The decrease of $1,978 million between 2001 and 2000 is
attributable to the California energy crisis previously discussed.
Cash Flows from Investing Activities
- ------------------------------------
Cash used in investing activities was $1,065 million during the six months ended
June 30, 2001, compared with $680 million used during the same period for 2000.
In 2001, the primary use of cash for investing activities was $818 million for
additions to property, plant, and equipment, compared with $670 million used for
similar purposes in 2000.
46
Cash Flows from Financing Activities
- ------------------------------------
Cash generated through financing activities for the six month ended June 30,
2001, was $152 million compared with $969 million used for the same period in
2000. A loan in 2001 netted $906 in proceeds which together with cash on hand
and from operating activities, were used to repay defaulted commercial paper and
other loans and the $109 million in dividends. The $969 million used in 2000
resulted from reduced borrowings of $482 million and a dividend payments of $217
million.
Utility
The following section discusses the Utility's significant cash flows from
operating, investing, and financing activities for the six-month periods ended
June 30, 2001.
Cash Flows from Operating Activities
- ------------------------------------
Net cash provided by the Utility's operating activities totaled $843 million and
$1,298 million for the six months ended June 30, 2001 and 2000, respectively.
The decrease of $455 million between 2001 and 2000 is primarily attributable to
higher cost of gas, offset by partial down payment of pre-petition obligations.
Cash Flows from Investing Activities
- -------------------------------------
The primary uses of cash for investing activities are additions to property,
plant, and equipment. The Utility's capital expenditures for the six-month
ended June 30, 2001, was $575 million.
Cash Flows from Financing Activities
- ------------------------------------
During the six months ended June 30, 2001, the Utility did not declare any
preferred or common stock dividends, compared with a payment of dividends on its
common stock of $250 million, for the six months ended June 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. Until its financial condition is restored, the
Utility is precluded from paying dividends to PG&E Corporation and PG&E
Holdings, LLC
The Utility's long-term debt that either matured, was redeemed, or was
repurchased during the six months ended June 30, 2001, totaled $252 million. Of
this amount, $141 million related to the Utility's rate reduction bonds
maturing, $93 million related to mortgage bonds maturing, and $18 million
related to the maturities and redemption of various of the Utility's 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
material debt. This facility was previously used to support the Utility's
commercial paper program and other liquidity requirements. At June 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 June 30, 2001, formerly backed by both this and another,
47
now cancelled, facility, was $873 million.
There was no new long-term debt issued in the period ended June 30, 2001. In
addition, there was no additional commercial paper issued during this same
period.
As of August 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: pollution control loan agreements, the 7.375%
senior notes, the $1.24 billion floating rate notes, commercial paper, bank loan
drawdowns, and other unsecured debt. Due to events of default under the credit
agreements with letter of credit banks, in April and May 2001, four letter of
credit banks accelerated and redeemed pollution control loans totaling $454
million. All of these redemptions were funded by the letter of credit banks
resulting in like obligations from the Utility to the banks.
Four other banks have made the May 1, June 1, July 1 and August 1, 2001,
interest payments on the $614 million principal amount of pollution control
bonds backed by letters of credit. The bond insurance company has made the June
1, 2001, interest payment for the pollution control bond backed by bond
insurance.
The Utility received notice from the QUIPS trustee 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 7.90% deferrable interest
subordinated debentures to bondholders. As of June 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 Consolidated Balance Sheet.
PG&E National Energy Group
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, and to 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
$987 million. PG&E NEG used a portion of the proceeds and intends to use the
balance of the senior notes issuance, net of $13 million of bond 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 principal amount of $1
48
billion, bear interest at 10.375% per annum, and mature on May 16, 2011.
In addition, PG&E Corporation historically has provided to the PG&E NEG credit
support for a range of contractual commitments. With respect to generating
facilities, this collateral 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 PG&E Energy
operations to provide short-term collateral to conterparties. As of June 30,
2001, except for $108 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, the PG&E NEG has experienced a substantial increase in the amount of
cash it has been required to place on deposit with various counterparties
without a commensurate increase in margin deposits received from counterparties.
The cash margin deposits outstanding to counterparties net of cash margin
received from counterparties increased from $10 million as of December 31, 2000
to $92 million as of June 30, 2001. 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. This new $550 million facility
has an initial 364-day term that expires on June 14, 2002.
Cash Flows from Operating Activities
- ------------------------------------
During the six months ended June 30, 2001, PG&E NEG generated net cash of $19
million in operating activities. Net cash from operating activities before
changes in other working capital accounts was $39 million, primarily driven by
net income. Net cash outflow related to certain other working capital accounts
was $20 million, driven primarily by an increase in margin deposits related to
PG&E NEG's trading activities.
Cash Flows from Investing Activities
- ------------------------------------
During the six months ended June 30, 2001, PG&E NEG used net cash of $523
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.
Cash Flows from Financing Activities
- ------------------------------------
Net cash generated by financing activities was $567 million for the six months
ended June 30, 2001 principally from the net proceeds related to the senior
notes.
RESULTS OF OPERATIONS
The table shows for the three- and six-months ended June 30, 2001 and 2000,
certain items from the Statement of Consolidated 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
49
elimination. Following this table we discuss our results of operations.
50
PG&E National Energy Group
-------------------------------------------
PG&E
Integrated Interstate Corporation
Energy and Pipeline NEG & Other
(in millions) Utility Total NEG Marketing Operations Eliminations Elimination(1) Total
------ -------- --------- --------- ------------ ------------- -------
Three months ended June 30, 2001
Operating revenues $2,309 $2,756 $2,679 $ 64 $13 $ (52) $ 5,013
Operating expenses 973 2,631 2,598 25 8 (38) 3,566
Operating income 1,447
Reorganization interest income 32
Interest income 42
Interest expense (312)
Other income (expenses), net 4
Income taxes 463
Net income 750
Net cash provided by operating activities 15
Net cash used by investing activities 566
Net cash provided by financing activities 584
EBITDA (2) 1,550 163 108 49 6 (3) 1,710
Three months ended June 30, 2000(3)
Operating revenues 2,296 3,362 3,090 280 (8) (20) 5,638
Operating expenses 1,744 3,280 3,060 229 (9) (8) 5,016
Operating income 622
Interest income 26
Interest expense (182)
Other income (expenses), net (14)
Income taxes 204
Net income 248
Net cash provided by operating activities 613
Net cash used by investing activities (440)
Net cash used by financing activities (126)
EBITDA (2) 602 111 52 58 1 (36) 677
Six months ended June 30, 2001
Operating revenues 4,871 6,964 6,831 129 4 (147) 11,688
Operating expenses 4,955 6,754 6,697 50 7 (128) 11,581
Operating income 107
Reorganization interest income 32
Interest income 77
Interest expense (559)
Other income (expenses), net (5)
Income taxes (147)
Net income (201)
Net cash provided by operating activities 697
Net cash used by investing activities (1,065)
Net cash provided by financing activities 152
EBITDA (2) 337 291 192 99 - (12) 648
Six months ended June 30, 2000(3)
Operating revenues 4,514 6,194 5,631 562 1 (62) 10,646
Operating expenses 3,392 6,002 5,541 460 1 (46) 9,348
Operating income 1,298
Interest income 50
Interest expense (365)
Other income (expenses), net (23)
Income taxes 432
Net income 528
Net cash provided by operating activities 1,675
Net cash used by investing activities (680)
Net cash used by financing activities (969)
EBITDA (2) $1,472 $ 253 $ 137 $116 $ - $ (34) $ 1,691
51
(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. EBITDA 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 7 of the Notes to the Condensed Consolidated
Financial Statements).
52
Overall Results
PG&E Corporation's financial position and results of operations continue to be
impacted by the ongoing 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 second quarter ended June 30, 2001 was
$750 million, compared to net income of $248 million for the same period in
2000, representing an increase of $502 million. The Utility's net income
available for common stock for the quarter ended June 30, 2001 accounted for
$480 million of the increase.
PG&E Corporation incurred a net loss of $201 million for the six-month period
ended June 30, 2001 compared to net income of $528 million for the same period
in 2000. Of the $729 million net decrease from the prior six-month period in
2000, the Utility was responsible for virtually all of the decrease, somewhat
offset by an 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 six-month periods ended June 30,
2001 and 2000 are generally attributable to the following factors:
- The Utility's earnings were impacted as a result of its under-collected
purchased power costs. Because of 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. For the six-month period ended June 30, 2001,
the total under-collected purchased power costs were $563 million, after-tax
of which $8 million, pre-tax are professional fees and expenses and reflected
within the reorganization sections of the consolidated statement of
operations. During the second quarter of 2001, the Utility recognized after-
tax offsets of $552 million against previously expensed purchased power costs.
These offsets included $327 million related to the market value of terminated
bilateral contracts and $155 million of adjustments to first quarter estimates
of ISO costs. The adjusted ISO costs resulted from actual billings received in
May 2001 for costs incurred in March 2001.
- As a result of the high cost of power, with no offsetting revenues, the
Utility and PG&E Corporation have a net loss for California tax purposes
through June 30, 2001. California law does not permit carrybacks of such
losses, and only permits carryforwards of 55% of such losses. As a result,
for the six-month period ended June 30, 2001, PG&E Corporation was unable to
recognize $8 million of state tax benefits because of California law.
- 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
53
of these borrowings was $61 million, after-tax, for the quarter ended June 30,
2001, and $103 million, after-tax, for the six-month period ended June 30,
2001.
- The Utility's filing of a petition of reorganization under Chapter 11 of
the U.S. Bankruptcy Code has resulted in incremental external financial and
legal expenses associated with the development of a plan of reorganization.
For the quarter ended June 30, 2001, these fees amounted to $9 million after-
tax of which $8 million, pre-tax, are professional fees and expenses reflected
within the reorganization section in the consolidated statement of operations.
For the six-month period ended June 30, 2001, total incremental external
financial and legal fees were $25 million after-tax.
- PG&E NEG increased earnings by $34 million for the three-month period ended
June 30, 2001, over the same period in 2000. The increase was a result of the
impact of favorable market movements on merchant generating plants and
increased pipeline utilization in the Pacific Northwest.
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 its 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
Utility
Overall Results
- ---------------
The Utility's net income was $696 million for the quarter ended June 30, 2001,
compared to $216 million for the same period in 2000. This increase in net
income was primarily the result of the recognition of the market value of
terminated bilateral contracts and the change in the amount of ISO accruals for
purchased power costs.
The Utility had a net loss of $304 million for the six-month period ended June
30, 2001, compared to the prior year's net income of $444 million. The change
in earnings was primarily the result of the $.9 billion charge to earnings for
under-collected purchased power costs in excess of the amounts provided in
54
customer rates for recovery of such costs. The under-collected amounts include
ISO charges incurred between January 1 and April 6, 2001. Generally accepted
accounting principles require that the amounts be accounted for as expenses
unless they can be deemed probable of recovery through the regulated rates. Due
to uncertainty created by the energy crisis, the Utility cannot meet the
accounting probability standard. This charge was partially offset by the
recognition of the value of the terminated bilateral contracts.
Operating Income
- ----------------
Operating income was $1,336 million for the second quarter ended June 30, 2001,
compared to operating income of $552 million for the same period in 2000. This
increase in operating income is primarily attributable to the recognition of the
value of the terminated bilateral contracts worth $552 million and the change in
the amount of the ISO accruals for purchased power costs.
The Utility had an operating loss of $84 million for the six months ended June
30, 2001, compared to operating income of $1,122 million for the same period in
2000. This change is due to the charge to earnings for under-collected
purchased power costs, as discussed above, which was partially offset by the
recognition of the value of the terminated bilateral contracts.
Operating Revenues
- ------------------
The Utility's operating revenues for the three months ended June 30 were $2.3
billion in both 2001 and 2000. Electric revenues decreased by $304 million for
the three months ended June 30, 2001, primarily due to the reduction of revenue
resulting from a portion of the Utility's billed revenues being passed through
to the DWR for the DWR'S electricity purchases which was partially offset by an
increase in customer revenues. Beginning in April 2001, the DWR began supplying
electric power to the Utility's customers in excess of that power generated by
or contracted for by the Utility. The Utility acts solely as a billing agent
for the DWR. Therefore, the amounts paid to the DWR for deliveries are not
recorded as expense and the revenue billed by the Utility to its customers
associated with this energy is excluded from revenues.
Gas revenues increased $317 million for the three months ended June 30, 2001,
due to the increased revenues from commercial and residential customers due to
higher gas costs resulting from high natural gas prices. Such costs are passed
on directly to customers.
The Utility's operating revenues for the six months ended June 30, 2001 were
$4.9 billion compared to operating revenues of $4.5 billion for the same period
in 2000. Gas revenues increased $1,003 million while electric revenues
decreased $646 million. The increase in gas revenues was primarily due to
increased revenues from residential and commercial customers due to higher
average cost of gas resulting from higher natural gas prices and increased usage
during 2001.
The decrease in electric revenues of $646 million was primarily due to credits
issued to direct access customers and due to the reduction of revenue resulting
from a portion of the Utility's billed revenues being passed through to the DWR
for the DWR's electricity purchases. As discussed above, these revenues are not
included in the Utility's reported revenues.
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
55
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, with the customer being obligated to their ESP at
their direct access contract rate.
For the six-month period ended June 30, 2001, the estimated total of accumulated
credits for direct access customers that have not been paid by the Utility is
approximately $354 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 FERC.
Operating Expenses
- ------------------
The table below summarizes the changes in the Utility's operating expenses:
Three months
ended June 30
------------------
Percentage
Increase Increase
(in millions) 2001 2000 (Decrease) (Decrease)
------- ------- -------- ----------
Cost of electric energy $ (362) $ 975 $ (1,337) (137) %
Cost of gas 429 182 247 136 %
Operating and maintenance 676 543 133 24 %
Depreciation, amortization, and decommissioning 222 44 178 405 %
Reorganization professional fees and expenses 8 - 8 -
---- ---- ----- ----
Total operating expenses $ 973 $ 1,744 $ (771) (44) %
==== ===== ===== ====
Six months Increase Increase
ended June 30 (Decrease) (Decrease)
------------------ -------- ----------
2001 2000
------- -------
Cost of electric energy $ 1,955 $ 1,488 $ 467 31 %
Cost of gas 1,345 465 880 189 %
Operating and maintenance 1,208 1,094 114 10 %
Depreciation, amortization, and decommissioning 439 345 94 27 %
Reorganization professional fees and expenses 8 - 8 -
---- ---- ----- ----
Total operating expenses $ 4,955 $ 3,392 $ 1,563 46 %
==== ===== ===== ====
The cost of electric energy decreased by $1,337 million for the three months
ended June 30, 2001 compared to the same period in 2000. This was attributable
to the recognition of the market value of several electric bilateral contract
terminations amounting to $552 million, a $261 million change in the amount of
the ISO related costs previously accrued and the impact of the fact that costs
of electric energy procured by the DWR are no longer reflected by the Utility.
In accordance with state legislation, the Utility does not take title to the
energy procured by the DWR for delivery to its customers. Rather, the Utility
acts solely as a billing agent for the DWR. Therefore, the amounts paid to the
DWR for deliveries are not recorded as expense and the revenue billed by the
Utility to its customers associated with this energy is excluded from revenues.
The cost of electric energy increased by $467 million for the six months ended
June 30, 2001 compared to the same period in 2000. This was attributable to the
higher average cost of electricity in 2001. Historically, the Utility generally
56
would have deferred such under-collected purchased power costs as a regulatory
asset to be collected from customers in future rates. However, due to the lack
of regulatory, legislative, or judicial relief, the Utility cannot conclude that
it is probable that its under-collected purchase power costs will be collected
in future rates. Therefore, in 2001 such costs are being expensed as incurred.
The higher costs were offset, in part, by the recognition of the market value of
electric bilateral contract terminations and the costs being passed through to
the DWR for the DWR's electricity purchases, as discussed above.
The cost of gas increased by $247 million and $880 million for the three months
and six months ended June 30, 2001, respectively, compared to the same periods
in 2000. The average cost of gas was $7.80 per decatherm (DTh) for the six
months ended June 30, 2001 compared to $2.59 per DTh for the same period in the
prior year. The procurement costs for gas are passed directly onto the
customers.
The Utility's operating and maintenance expenses increased $133 million in the
three-month period, and $114 million in the six-month period ending June 30,
2001 compared to the same periods in 2000. These increases are a result of a
Diablo Canyon refueling outage with no such outage in the similar periods of
2000, increased customer energy efficiency expenses and higher franchise
requirements fees resulting from higher electric and gas revenue.
Depreciation, amortization, and decommissioning increased by $178 million in the
three-month period, and $94 million in the six-month period ending June 30, 2001
compared to the same periods in 2000. These increases are due to the
elimination of regulatory asset deferrals for generation-related transition
costs in 2001. In 2000, when generation-related regulatory assets were
amortized to depreciation, amortization and decommissioning expense and when
purchased power costs were under-collected, the Utility would defer the under-
collections by reducing depreciation, amortization and decommissioning expense.
Since the Utility wrote off its generation-related regulatory assets and under-
collected purchased power costs in 2000 and continues to expense as incurred its
under-collected purchased power costs in 2001, no such deferral and reduction to
depreciation, amortization, and decommissioning expense occurs in 2001.
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. Until its financial condition is restored, the Utility is precluded from
paying dividends to PG&E Corporation and PG&E Holdings, LLC
PG&E National Energy Group
Operating Income
- -----------------
Operating income at PG&E NEG was $125 million for the second quarter ended June
30, 2001 compared to $82 million for the same period in 2000. For the six-month
period ended June 30, 2001, operating income was $210 million, compared to $192
million for the same period in 2000.
Operating Revenues
- -----------------
Operating revenues were $2.8 billion in the three months ended June 30, 2001, a
decrease of $.7 billion, or 21%, from the three months ended June 30, 2000.
57
Operating revenues for PG&E Energy decreased by $.5 billion, or 17% primarily as
the result of decreased commodity sales and a decline in the market value of
long-term gas transportation contracts. Operating revenues for PG&E Pipeline
decreased by $216 million. Short-term firm revenues earned by PG&E Pipeline
operations increased, resulting from higher usage and higher negotiated rates.
However, these increases were offset by the completion of the sale of PG&E GTT
in late 2000, which had revenues of $224 million for the three months ended June
30, 2000.
Operating revenues were $7.0 billion in the six months ended June 30, 2001, an
increase of $.3 billion, or 4%, from the six months ended June 30, 2000.
Operating revenues for PG&E Energy increased by $.7 billion as a result of
increases in the price of power and gas, and a focus of trading efforts on asset
management and higher-margin trades. These increases were partially offset by
decreases in commodity sales and declines in the market value of long-term gas
transportation contracts during the second quarter. Operating revenues for PG&E
Pipeline decreased by $433 million. Short-term firm revenues earned by pipeline
increased, resulting from higher usage and higher negotiated rates. These
increases were offset by the completion of the sale of PG&E GTT in late 2000,
which had revenues of $449 million for the six months ended June 30, 2000.
Operating Expenses
- ------------------
Operating expenses were $2.6 billion in the three months ended June 30, 2001, a
decrease of $.8 billion, or 23%, from the three months ended June 30, 2000. The
decrease primarily resulted from the lower quantity of PG&E Energy commodity
sales, overall reduced operational costs at our facilities, and the reduction of
costs associated with the sale of PG&E GTT in late 2000 from PG&E Pipeline
segment.
Operating expenses were $6.8 billion in the six months ended June 30, 2001, an
increase of $.3 billion, or 4%, from the six months ended June 30, 2000. The
increase primarily resulted from higher costs of commodities and fuel in the
PG&E Energy segment, partially offset by overall reduced operational costs at
PG&E NEG facilities, and the reduction of costs as a result of the sale of PG&E
GTT in late 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.)
58
The Utility's General Rate Case (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.
In March 2000, two interveners filed applications for rehearing of the Utility's
1999 GRC decision, alleging that the CPUC committed legal errors by approving
funding in certain areas that were not adequately supported by record evidence.
In April 2000, the Utility filed its response to these applications for
rehearing, defending the GRC decision against the allegations of error. A CPUC
decision on the applications for rehearing is pending.
In the 1999 GRC decision, the CPUC ordered that the Utility file a 2002 GRC. As
a result of the current energy crisis, the procedural schedule has been delayed
pending the CPUC's resolution of the Utility's request that it be permitted to
file an alternative schedule or an alternative to the 2002 GRC. An earlier
decision initially delaying the schedule affirms that rates would still become
effective on January 1, 2002, although the CPUC decision may not be rendered
until after that date.
Order Instituting Investigation (OII) into Holding Company Activities
On April 3, 2001, the CPUC issued an order instituting an investigation 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
U.S. 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
59
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
in the ratesetting category.
The Utility's 2001 Attrition Rate Adjustment (ARA)
In July 2000, the Utility filed an ARA application with the CPUC to increase its
2001 electric distribution revenues by $189 million, effective January 1, 2001.
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. On May 8, 2001, the CPUC's Office of Ratepayer
Advocates (ORA) submitted its report on the Utility's request, recommending that
the CPUC deny the Utility's request. The Utility believes that ORA's
recommendations are unjustified and challenged those recommendations in hearings
in June 2001.
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
60
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
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, PG&E filed at FERC to increase its power and transmission related
rates to the Western Area Power Administration (Western). The majority of the
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. In this filing, the Utility estimates
that if FERC grants its request, it will collect from Western an additional
$1,125 million before the contract terminates on December 31, 2004, thereby
reducing the revenue that needs to be collected through existing electric retail
rates.
ENVIRONMENTAL MATTERS
We are subject to laws and regulations established to both maintain and improve
the quality of the environment. Where our properties contain hazardous
substances, these laws and regulations require us to remove those substances or
remedy effects on the environment. See Note 6 of 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 June 30, 2001, the Utility expects to spend $306 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 $459 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
61
clean-up costs at additional sites or expected outcomes change.
The Utility had an environmental remediation liability of $306 million and $320
million at June 30, 2001 and December 31, 2000, respectively. The $306 million
accrued at June 30, 2001 includes (1) $139 million related to the pre-closing
remediation liability, associated with divested generation facilities (see
further discussion in the "Generation Valuation " section of Note 2 of the Notes
to the Condensed Consolidated Financial Statements), and (2) $167 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 $306 million environmental remediation liability, the Utility has
recovered $139 million through rates, and expects to recover another $86 million
in future rates. The Utility is seeking recovery of the remainder of 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 (i) 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 (ii) any additional amounts necessary in emergency
situations involving post-petition releases or threatened releases of hazardous
substances, if such excess expenditures is 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.
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. 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 "best technology
62
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 $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.
The Utility believes the ultimate outcome of these matters will not have a
material impact on the Utility's financial position or results of operations.
PG&E National Energy Group
The U.S. Environmental Protection Agency (EPA) has been conducting a nationwide
enforcement investigation regarding the historical compliance of coal-fueled
electric generating stations with various permitting requirements of the Clean
Air Act. Specifically, the EPA and the U.S. Department of Justice have recently
initiated enforcement actions against a number of electric utilities, several of
which have entered into substantial settlements for alleged Clean Air Act
violations related to modifications (sometimes more than 20 years ago) of
existing coal-fired generating facilities. In May 2000, PG&E NEG received a
request for information seeking detailed operating and maintenance histories for
the Salem Harbor and Brayton Point power plants and, in November 2000, the EPA
visited both facilities. PG&E NEG believes this request for information is part
of the EPA's industry-wide investigation of coal-fired power plants' compliance
with the Clean Air Act requirements governing plant modifications. PG&E NEG
also believes that any changes it made to these plants were routine maintenance
or repair and, therefore, did not require permits. The EPA has not issued a
notice of violation or filed any enforcement action against PG&E NEG at this
time. Nevertheless, if the EPA disagrees with PG&E NEG's conclusions with
respect to the changes PG&E NEG made at the facilities, and successfully brings
an enforcement action against PG&E NEG, then penalties may be imposed and
further emission reductions might be necessary at these plants.
From time to time various states in which our facilities are located consider
the adoption of air emissions standards that may be more stringent than those
imposed by the EPA. On May 11, 2001, the Massachusetts Department of
Environmental Protection (DEP) issued regulations imposing new restrictions on
emissions of NOx and SO2, mercury and carbon dioxide from existing coal-fired
power plants. These restrictions will impose more stringent annual and monthly
limits on NOx and SO2 emissions than currently exist and will take effect in
stages, beginning in October 2004 if no permits are needed for the changes
necessary to comply, and beginning in 2006 if such permits are needed. The DEP
has informed PG&E NEG that, based upon its current understanding of the
facilities' plans for compliance with the new regulations, it believes that
permits will be needed and that the initial compliance date will therefore by
2006. However, the need for permits triggers an obligation to meet Best
Available Control Technology (BACT) requirements. Compliance with BACT at the
facilities could require implementation of controls beyond those otherwise
necessary to meet the emissions standards in the new regulations. Mercury
emissions are capped as a first step and must be reduced by October 2006
pursuant to standards to be developed. Carbon dioxide emissions are regulated
for the first time and must be reduced from recent historical levels. PG&E NEG
believes that compliance with the carbon dioxide caps can be achieved through
implementation of a number of strategies, including sequestrations and offsite
reductions. Various testing and recordkeeping requirements are also imposed.
By 2002, PG&E NEG plans to have approximately 5,100 MW of generating capacity in
operation in New England. The new Massachusetts regulations affect primarily
its Brayton Point and Salem Harbor generating facilities, representing
approximately 2,300 MW. Through 2006, it may be necessary to spend
63
approximately $265 million to comply with these regulations. In addition, with
respect to approximately 600 MW (or about 12%) of PG&E NEG's New England
capacity, PG&E NEG may need to implement fuel conversion, limit operations, or
install additional environmental controls. These new regulations require that
PG&E NEG achieve specified emission levels earlier than the dates included in a
previous Massachusetts initiative to which it had agreed.
The Federal Clean Water Act generally prohibits the discharge of any pollutants,
including heat, into any body of surface water, except in compliance with a
discharge permit issued by a state environmental regulatory agency and/or the
EPA. All of the facilities that are required to have such permits either have
them or have timely applied for extensions of expired permits and are operating
in substantial compliance with the prior permit. At this time, three of the
fossil-fuel plants owned and operated by an affiliate of PG&E NEG USGen New
England, Inc. (Manchester Street, Brayton Point and Salem Harbor stations) are
operating pursuant to permits that have expired. For the facilities whose NPDES
permits have expired, permit renewal applications are pending, and PG&E NEG
anticipates that all three facilities will be able to continue to operate in
substantial compliance with prior permits until new permits are issued. It is
estimated that USGen New England's cost to comply with new permit conditions
could be approximately $60 million through 2005. It is possible that the new
permits may contain more stringent limitations than the prior permit.
PG&E NEG anticipates spending up to approximately $330 million, net of insurance
proceeds, through 2006 for environmental compliance at currently operating
facilities, which primarily addresses: (a) new Massachusetts air regulations
made public on April 23, 2001 affecting the Brayton Point and Salem Harbor
Stations; (b) wastewater permitting requirements that may apply to the Brayton
Point, Salem Harbor and Manchester Street Stations; and (c) requirements, to
which PG&E NEG agreed, that are reflected in a consent decree concerning
wastewater treatment facilities at the Salem Harbor and Brayton Point Stations.
During April 2000, an environmental group served USGen New England, Inc., and
other subsidiaries with a notice of its intent to file a citizen's suit under
RCRA. The group stated that it planned to allege that USGen New England, Inc.
as the generator of fossil fuel combustion wastes at Salem Harbor and Brayton
Point, has contributed and is contributing to the past and present handling,
storage, treatment and disposal of wastes at those facilities which may present
an imminent and substantial endangerment to the public health or the
environment. During September 2000, USGen New England, Inc. signed a series of
agreements with the Massachusetts Department of Environmental Protection and the
environmental group that address and resolve these matters. The agreements,
which have been filed in federal court and are now incorporated in a consent
decree, require, among other things, that USGen New England, Inc. alter its
existing wastewater treatment facilities at both facilities by replacing certain
unlined treatment basins, submit and implement a plan for the closure of such
basins, and perform certain environmental testing at the facilities. Although
the outcome of such environmental testing could lead to higher costs, the total
cost of these activities is expected to be approximately $21 million, and they
are underway.
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). We use derivatives 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
64
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 only engage in the trading of
derivatives 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 is primarily exposed to the
commodity price risk associated with energy commodities such as electricity and
natural gas. Therefore, PG&E Corporation'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
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 their exposure to commodity price fluctuations because of the reluctance
of counterparties 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,
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
65
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. Many existing bilateral
contracts were terminated 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
made by DWR to meet the Utility's net open position. The Utility is currently
paying DWR the amount of money it collects in retail rates for electricity (that
is, excluding transmission, distribution, and other costs). The Utility
believes that it is only obligated to pass through the amount it collects in
electricity rates, and therefore, there is no price risk for electricity
purchases to serve the net open position.
Although responsibility for the net open position currently lies with the DWR,
it is anticipated that this responsibility will be transferred back to the
Utility at an unknown future date. As explained in Note 2 of the Notes to the
Condensed Consolidated Financial Statements, the Utility believes that the
conditions required to end the rate freeze on retail electricity rates were met
in 2000, after which time power purchase costs would be included in retail
electricity rates. Electricity commodity price risks after the rate freeze ends
would depend on how retail rates are determined. If traditional cost-of-service
ratemaking methods are used, electricity commodity price risks would not have a
material impact on PG&E Corporation's financial results.
Utility Natural Gas Commodity Price Risk
Under a rate-making 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 benchmark price reflects a weighting of spot and forward
gas prices 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 method called the Gas Accord, 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,
although this exposure is mitigated through forward contracts.
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.
PG&E Corporation and its subsidiaries measure commodity price risk exposure
using value-at-risk and other methodologies that simulate future price movements
66
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 and only derivative commodity instruments for
PG&E NEG's non-trading portfolio (not the related underlying hedged position).
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 June 30, 2001, was $11 million for its natural gas business.
The Utility believes that there is currently no commodity price risk associated
with fluctuating electric power prices, because these costs should be fully
reflected in future retail rates.
PG&E NEG's daily value-at-risk commodity price risk exposure as of June 30,
2001, was $15 million for trading activities and $36 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 is exposed to changes in interest rates primarily as a result
of its variable rate commercial paper, bonds, bank loans, floating rate notes,
project financing, and investing activities. In addition, PG&E Corporation is
exposed to changes in interest rates on interest accruing on loan payments and
trade payables currently in default. 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
uses sensitivity analysis to measure its interest rate price risk by computing
estimated changes in cash flows as a result of assumed changes in market
interest rates. As of June 30, 2001, if interest rates had averaged 1% higher,
PG&E Corporation's earnings would have decreased by approximately $17 million.
Foreign Currency Risk
PG&E Corporation is 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 uses
sensitivity analysis to measure its foreign currency exchange rate exposure to
the Canadian dollar. As of June 30, 2001, if the Canadian dollar experienced a
10% devaluation, estimated losses would not have had a material impact on PG&E
67
Corporation's 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 6 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 primary market risk
results from changes in energy prices and interest rates. We engage in price
risk management activities for both trading and non-trading purposes.
Additionally, we 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, the Utility filed a voluntary petition
for relief under the provisions of Chapter 11 of the United States Bankruptcy
Code. 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). The last day for non-governmental
unit creditors to file proofs of claim is September 5, 2001 and the last day for
government entities to file proof of claims is October 3, 2001.
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 Report on Form 10-Q filed by PG&E Corporation and
Pacific Gas and Electric Company for the quarter ended March 31, 2001. More
recently, the Bankruptcy Court has approved the Utility's assumption of various
hydroelectric contracts with water agencies and irrigation districts, the
implementation of a management retention program, and the continuation of
environmental remediation and capital expenditure programs. Other recent
proceedings are discussed below.
On May 18, 2001, the Bankruptcy Court vacated the United States Trustee's
appointment of a ratepayers' committee finding that the Bankruptcy Code does not
authorize the creation of such a committee. Under the Bankruptcy Code, only
creditors and equity security holders are eligible for appointment to a
committee by the U.S. Trustee. The Bankruptcy Court noted that under the
Bankruptcy Code, there are legitimate ways by which the ratepayers can be
represented and heard in the process, for example, through the California
Attorney General's Office. In addition, the Bankruptcy Code provides
flexibility and discretion to the court to allow parties to intervene in the
case when they have standing to do so. On July 10, 2001, the Bankruptcy Court
denied the U.S. Trustee's motion to reconsider its earlier order.
On June 1, 2001, the Bankruptcy Court issued a decision denying the Utility's
request for an injunction against the California Public Utilities Commission
(CPUC) and its Commissioners to prohibit the implementation or enforcement of
the CPUC's March 27, 2001 decision adopting changes to the transition period
accounting mechanisms. The Court also granted the CPUC's motion to dismiss the
complaint. Although the Court held that the Eleventh Amendment to the U.S.
Constitution did not bar the Utility's suit against the individual
Commissioners, the Court concluded that the Utility was not entitled to a stay
or an injunction to prevent implementation and enforcement of the regulatory
accounting order. First, the Court held that, assuming the Bankruptcy Code
provision imposing an automatic stay on pre-petition proceedings might
ordinarily apply (an issue that the Court expressly declined to decide), the
Court determined that the Commissioners were acting pursuant to their police and
regulatory power when issuing the order. Accordingly, the Court found that the
order was exempt from the automatic stay provision pursuant to a statutory
exemption for the commencement or continuation of an action or proceeding by a
governmental unit to enforce such governmental unit's police and regulatory
70
power. Second, the Court held that the Utility had not shown any actual or
threatened violation of federal law sufficient to warrant injunctive relief, nor
did the balance of equities favor an injunction. The Utility's application for
rehearing of the CPUC's decision remains pending at the CPUC. The Utility has
initiated an appeal of the Bankruptcy Court's decision to the United States
District Court for the Northern District of California, and the CPUC and its
Commissioners have initiated a cross-appeal, both of which are pending.
The first meeting of creditors was held as scheduled on June 7, 2001. Senior
executives of the Utility made themselves available to respond to questions from
the U.S. Trustee and participating creditors about the Utility's assets,
liabilities and administration of the Chapter 11 estate.
As previously disclosed, the Utility filed a complaint for injunctive and
declaratory relief in the Bankruptcy Court asking the court to prohibit 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 the order issued on February 14, 2001, the FERC
rejected the ISO's January 5, 2001 proposed tariff amendment which would have
waived certain credit standards relating to third party transactions and ordered
that the ISO could only engage in power purchases on behalf of creditworthy
entities. The Utility has not met the creditworthiness standards of the ISO
tariff since January 4, 2001. Despite the FERC orders, the ISO has continued to
bill the Utility for the ISO's wholesale power purchases.
On June 18, 2001 the Bankruptcy Court granted a motion by Reliant Energy, Inc.
and Reliant Energy Services, Inc. (collectively, Reliant) to intervene in the
Utility's action against the ISO. Reliant has intervened in the action to seek
a permanent injunction barring the ISO from procuring power to meet the
Utility's net short position in violation of its tariff and applicable FERC
orders. If the Bankruptcy Court declines to issue such an injunction, Reliant
has asked the Bankruptcy Court in the alternative to declare that the Utility is
liable to Reliant for power procured by the ISO from Reliant and delivered to
the Utility's service area.
On June 26, 2001, the Bankruptcy Court issued a preliminary injunction in the
Utility's action against the ISO, prohibiting the ISO from violating the FERC
orders discussed above and from filing administrative claims against the Utility
in the bankruptcy for ISO charges for wholesale power purchases and other
services in the ISO market. 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 counterparty, 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. The Utility believes that its only responsibility for
third party power delivered to its customers and related costs since it ceased
to be creditworthy is to pay the DWR the amount collected from customers
pursuant to AB 1X.
In addition to alleging violations of the FERC orders and the creditworthiness
provisions of the ISO tariff, the Utility's complaint also seeks to have the
court declare that any action by the ISO to purchase wholesale power for or on
behalf of the Utility at costs the Utility is not permitted to fully recover
through the generation- related cost component of retail rates, to compel the
Utility to accept and pay for such purchases, or to accrue post-petition debt
for such purchases (i.e., to accrue debts after April 6, 2001, when the Utility
filed its petition under Chapter 11 of the federal Bankruptcy Code), is
automatically stayed by bankruptcy law and violates other provisions of the
Bankruptcy Code. In addition, the complaint seeks a permanent injunction
prohibiting the ISO from taking such actions.
71
On July 20, 2001, the Bankruptcy Court granted the Utility's unopposed motion to
extend the period during which the Utility has the exclusive right to file with
the Bankruptcy Court a plan of reorganization that specifies, among other
things, the treatment of claims. Although the initial 120-day period was to
expire on August 6, 2001, the court extended the exclusivity period until
December 6, 2001. If the Utility files a plan of reorganization before December
6, 2001, the exclusivity period will be extended automatically until February 4,
2002, giving the Bankruptcy Court time to consider confirmation of the Utility's
plan. After the exclusivity period, and assuming the Bankruptcy Court has not
yet confirmed the Utility's plan of reorganization, creditors and other parties
in interest may file their own plan of reorganization.
Further, during July 2001, the Utility reached agreements with 131 of the
Utility's QF suppliers, representing about 1,600 MW of the average annual 2,400
MW that the Utility receives from its QFs. Under the agreements, the Utility
will assume the existing QF contracts, as modified to require the Utility to pay
the QFs a fixed average energy price of 5.37 cents per kWh for five years.
Currently, the contracts require the Utility to pay the QFs a price that
fluctuates with natural gas prices. In addition, the Utility has agreed to pay
the pre-petition debt on these 131 contracts, approximately $740 million, on the
effective date of the plan of reorganization. The total amount of debt the
Utility owed to QFs when it filed bankruptcy was approximately $1 billion. For
certain QFs, if the effective date has not occurred by July 15, 2003, the
Utility has agreed to pay 2% of the principal amount of the pre-petition debt
per month until the effective date of the plan of reorganization or until July
15, 2005, when the Utility would pay the remaining pre-petition debt. The
agreements require the approval of the Bankruptcy Court before they can become
effective. Most of the agreements have already been approved and the Utility
has filed or will file motions asking the Bankruptcy Court to approve the
remaining agreements. The proposed agreements contain modifications approved by
the CPUC in a decision issued on June 13, 2001, whereby certain QFs under
Standard Offer contracts with the Utility who establish hardship may request
that their contracts be modified to replace the energy pricing term with a one-
year energy price that establishes the Utility's full short-run avoided
operating costs as the lesser of (a) the energy price determined under the
short-run avoided energy price formula previously adopted by the CPUC for the
Utility, as in effect on March 1, 2001, or (b) the energy price determined under
the short-run avoided energy price formula previously adopted by the CPUC for
the Utility, as in effect on March 1, 2001, but with the QFs' actual California
border gas costs substituted for the Malin and Topock gas index prices otherwise
used in such formula.
Federal Securities Lawsuit
By order entered on or about May 31, 2001, the action entitled Jack Gillam;
DOES 1 TO 5, Inclusive, and All Persons similarly situated vs. PG&E Corporation,
Pacific Gas and Electric Company; and DOES 6 to 10, Inclusive, described in the
Quarterly Report on Form 10-Q filed by PG&E Corporation and Pacific Gas and
Electric Company for the quarter ended March 31, 2001, was transferred from the
U.S. District Court for the Central District of California to the U.S. District
Court for the Northern District of California.
For a discussion of other pending legal proceedings, see the Annual Report on
Form 10-K filed by PG&E Corporation and Pacific Gas and Electric Company for the
year ended December 31, 2000, and the Quarterly Report on Form 10-Q filed by
PG&E Corporation and Pacific Gas and Electric Company for the quarter ended
March 31, 2001,
72
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 June 30, 2001, the
Utility had issued and outstanding 5,784,824 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 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 ending
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 ending January 31 and April 30, 2001, amounted to $12.7 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 June 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 June 30, 2001, the Utility has not made 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 U.S. 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 like obligations from the Utility to the banks, which have not been
paid. As of June 30, 2001, the total principal of the bonds (and related loans)
73
accelerated and redeemed was $454 million. As of June 30, 2001, the Utility did
not make interest payments of $5.2 million on pollution control bonds series
96C, E, F and 97B. As of June 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
U.S. Bankruptcy Code also constitutes a default under the indenture that governs
its 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
June 30, 2001, the Utility has not made interest payments on its 7.375% senior
notes and its $1.24 billion floating rate notes. As of June 30, 2001, the total
arrearage of these interest payments was $48.3 million. Also as of June 30,
2001, the Utility did not make interest payments on other long-term debt of $.5
million.
With regard to the 7.90% Quarterly Income Preferred Securities (QUIPS) and the
related 7.90% Deferrable Interest Debentures (debentures), the Utility's filing
of a petition for reorganization under Chapter 11 of the U.S. 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 4. Submission of Matters to a Vote of Security Holders
PG&E Corporation:
On May 16, 2001, PG&E Corporation held its annual meeting of shareholders. At
that meeting, the shareholders voted as indicated below on the following
matters:
1. Election of the following directors to serve until the next annual meeting
of shareholders or until their successors are elected and qualified
(included as Item 1 in proxy statement):
For Withheld
-------------- ------------
David R. Andrews 258,499,976 17,939,124
David A. Coulter 261,767,229 14,671,871
C. Lee Cox 261,954,208 14,484,892
William S. Davila 261,901,022 14,538,078
Robert D. Glynn, Jr. 261,618,101 14,820,999
David M. Lawrence, MD 261,873,600 14,565,500
Mary S. Metz 261,742,063 14,697,037
Carl E. Reichardt 261,752,099 14,687,001
Barry Lawson Williams 261,728,932 14,710,168
2. Ratification of the appointment of Deloitte & Touche LLP as independent
public accountants for 2001 (included as Item 2 in proxy statement):
For: 266,161,911
Against: 7,186,368
Abstain: 3,090,821
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The proposal was approved by a majority of the shares represented and voting
(including abstentions) which shares voting affirmatively also constituted a
majority of the required quorum.
3. Management proposal regarding increase in shares available to be issued
under the PG&E Corporation Long Term Incentive Program (included as Item 3
in proxy statement).
For: 227,672,764
Against: 44,286,370
Abstain: 4,479,966
Broker non-vote: 0
The proposal was approved by a majority of the shares represented and voting
(including abstentions) which shares voting affirmatively also constituted a
majority of the required quorum.
4. Consideration of a shareholder proposal regarding confidential shareholder
voting (included as Item 4 in proxy statement):
For: 57,869,881
Against: 165,503,947
Abstain: 6,072,815
Broker non-vote: (1) 46,992,457
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the shares
represented and voting (including abstentions but excluding broker non-
votes) with respect to the proposal.
5. Consideration of a shareholder proposal regarding the treatment
of abstentions (included as Item 5 in proxy statement):
For: 36,456,683
Against: 186,712,779
Abstain: 6,277,181
Broker non-vote: (1) 46,992,457
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the shares
represented and voting (including abstentions but excluding broker non-
votes) with respect to the proposal.
6. Consideration of a shareholder proposal regarding cumulative voting
(included as Item 6 in proxy statement):
For: 32,248,291
Against: 190,607,501
Abstain: 6,590,851
Broker non-vote: (1) 46,992,457
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the shares
represented and voting (including abstentions but excluding broker non-
votes) with respect to the proposal.
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7. Consideration of a shareholder proposal regarding the minimum number of
directors (included as Item 7 in proxy statement):
For: 18,633,524
Against: 204,574,825
Abstain: 6,238,294
Broker non-vote: (1) 46,992,457
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the shares
represented and voting (including abstentions but excluding broker non-
votes) with respect to the proposal.
8. Consideration of a shareholder proposal regarding the fair price provision
(Article Eighth of the Articles of Incorporation) (included as Item 8 in
proxy statement):
For: 127,746,676
Against: 95,311,869
Abstain: 6,238,294
Broker non-vote: (1) 46,992,457
This shareholder proposal was approved as the number of shares voting
affirmatively on the proposal constituted more than a majority of the shares
represented and voting (including abstentions but excluding broker non-
votes) with respect to the proposal, and the affirmative votes constituted a
majority of the required quorum.
9. Consideration of a shareholder floor proposal introduced at the annual
meeting regarding company statements in opposition to shareholder proposals
was duly and properly conducted by ballot.
For: 26,744
Against: 276,403,728
Abstain: 874
Broker non-vote: (1) 0
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the shares
represented and voting (including abstentions) with respect to the proposal.
10. Consideration of a shareholder floor proposal introduced at the annual
meeting regarding company recommendations for voting on shareholder
proposals was duly and properly conducted by ballot.
For: 27,472
Against: 276,403,492
Abstain: 774
Broker non-vote: (1) 0
- --------------------
(1) A non-vote occurs when a broker or other nominee holding shares for a
beneficial owner indicates a vote on one or more proposals, but does not
indicate a vote on other proposals because the broker or other nominee does not
have discretionary voting power as to such proposals and has not received voting
instructions from the beneficial owner as to such proposals.
76
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the shares
represented and voting (including abstentions) with respect to the proposal.
11. Consideration of a shareholder floor proposal introduced at the annual
meeting regarding information on directors' business relationships with PG&E
Corporation was duly and properly conducted by ballot.
For: 29,824
Against: 276,401,140
Abstain: 774
Broker non-vote: (1) 0
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the shares
represented and voting (including abstentions) with respect to the proposal.
12. Consideration of a shareholder floor proposal introduced at the annual
meeting regarding information on executive and director compensation was
duly and properly conducted by ballot.
For: 29,804
Against: 276,401,160
Abstain: 774
Broker non-vote: (1) 0
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the shares
represented and voting (including abstentions) with respect to the proposal.
13. Consideration of a shareholder floor proposal introduced at the annual
meeting regarding information on 2001 executive compensation was duly and
properly conducted by ballot.
For: 29,032
Against: 276,401,760
Abstain: 506
Broker non-vote: (1) 0
This shareholder proposal was defeated, as the number of shares voting
affirmatively on the proposal constituted less than a majority of the shares
represented and voting (including abstentions) with respect to the proposal.
Pacific Gas and Electric Company:
On May 16, 2001, Pacific Gas and Electric Company held its annual meeting of
shareholders. Shares of capital stock of Pacific Gas and Electric Company
consist of shares of common stock and shares of first preferred stock. As PG&E
Corporation and a subsidiary own all of the outstanding shares of common stock,
they hold approximately 95% of the combined voting power of the outstanding
77
capital stock of Pacific Gas and Electric Company. PG&E Corporation and the
subsidiary voted all of their respective shares of common stock for the nominees
named in the 2001 joint proxy statement and for the ratification of the
appointment of Deloitte & Touche LLP as independent public accountants for 2001.
The balance of the votes shown below were cast by holders of shares of first
preferred stock. At the annual meeting, the shareholders voted as indicated
below on the following matters:
1. Election of the following directors to serve until the next annual meeting
of shareholders or until their successors are elected and qualified:
For Withheld
----------- ---------
David R. Andrews 338,304,620 637,790
David A. Coulter 338,321,293 621,117
C. Lee Cox 338,324,918 617,492
William S. Davila 338,331,671 610,739
Robert D. Glynn, Jr. 337,063,120 1,879,290
David M. Lawrence, MD 338,330,527 611,883
Mary S. Metz 338,327,998 614,412
Carl E. Reichardt 338,328,014 614,396
Gordon R. Smith 337,063,937 1,878,473
Barry Lawson Williams 338,324,783 617,627
2. Ratification of the appointment of Deloitte & Touche LLP as independent
public accountants for 2001:
For: 338,679,391
Against: 111,360
Abstain: 151,659
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 six
months ended June 30, 2001, was a negative 0.06. Pacific Gas and Electric
Company's earnings to combined fixed charges and preferred stock dividends ratio
for the six months ended June 30, 2001, was a negative 0.05. The negative
ratios of earnings to fixed charges and earnings to combined fixed charges and
preferred stock dividends indicates a deficiency in earnings of $492 million and
$510 million respectively. 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 PG&E Corporation Long-Term Incentive Program, as
amended effective May 16, 3001
78
Exhibit 11 Computation of Earnings Per Common Shares
Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges for
Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas
and Electric Company
(b) The following Current Reports on Form 8-K were filed during the first
quarter of 2001 and through the date hereof (2):
1. April 6, 2001 (as amended) filed by PG&E Corporation only
Item 5. Other Events - Pacific Gas and Electric Company Bankruptcy
2. April 6, 2001 (as amended) filed by Pacific Gas and Electric Company
only
Item 3. Other Events - Bankruptcy or Receivership.
3. May 2, 2001
Item 9. Regulation FD Disclosure
4. May 7, 2001 - filed by PG&E Corporation only
Item 9. Regulation FD Disclosure
5. May 8, 2001
Item 5. Other Events
A. Federal Lawsuit
B. Pacific Gas and Electric Company Bankruptcy
6. June 6, 2001
Item 5. Other Events
Pacific Gas and Electric Company Bankruptcy
Item 9. Regulation FD Disclosure
7. July 9, 2001
Item 5. Other Events
8. July 30, 2001
Item 5. Other Events
79
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
Vice President and Controller
(duly authorized officer and principal
accounting officer)
PACIFIC GAS AND ELECTRIC COMPANY
By: DINYAR B. MISTRY
----------------
DINYAR B. MISTRY
Vice President and Controller
(duly authorized officer and principal
accounting officer)
Dated: August 1, 2001
80
Exhibit Index
Exhibit No. Description of Exhibit
------------- --------------------------------------------------------
Exhibit 10 PG&E Corporation Long-Term Incentive Program, as amended
effective May 16, 3001
Exhibit 11 Computation of Earnings Per Common Shares
Exhibit 12.1 Computation of Ratios of Earnings to Fixed Charges for
Pacific Gas and Electric Company
Exhibit 12.2 Computation of Ratios of Earnings to Combined Fixed
Charges and Preferred Stock Dividends for Pacific Gas and
Electric Company
81